FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2001
OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to _______
Commission file number: 1-14323
Enterprise Products Partners L.P.
(Exact name of Registrant as specified in its charter)
Delaware 76-0568219
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2727 North Loop West
Houston, Texas
77008-1037
(Address of principal executive offices) (Zip code)
(713) 880-6500
(Registrant's telephone number including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days.
Yes _X_ No ___
The registrant had 51,524,515 Common Units outstanding as of August 13, 2001.
Enterprise Products Partners L.P. and Subsidiaries
TABLE OF CONTENTS
Page
No.
----
Glossary
Part I. Financial Information
Item 1. Consolidated Financial Statements
Enterprise Products Partners L.P. Unaudited Consolidated Financial Statements:
Consolidated Balance Sheets, June 30, 2001 and December 31, 2000 1
Statements of Consolidated Operations
for the three and six months ended June 30, 2001 and 2000 2
Statements of Consolidated Cash Flows
for the three and six months ended June 30, 2001 and 2000 3
Statements of Consolidated Partners' Equity and Comprehensive Income
for the three and six months ended June 30, 2001 and 2000 4
Notes to Unaudited Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operation 22
Item 3. Quantitative and Qualitative Disclosures about Market Risk 36
Part II. Other Information
Item 2. Use of Proceeds 40
Item 6. Exhibits and Reports on Form 8-K 41
Signature Page
Glossary
The following abbreviations, acronyms or terms used in this Form 10-Q are defined below:
Acadian Gas Acadian Gas, LLC
BBtu/d Billion British thermal units per day, a measure of heating value
Bcf Billion cubic feet
Bcf/d Billion cubic feet per day
BPD Barrels per day
Btu British thermal unit, a measure of heating value
Company Enterprise Products Partners L.P. and subsidiaries
Enron Enron North America Corp. and subsidiaries
EPCO Enterprise Products Company, an affiliate of the Company
EPE El Paso Corporation, its subsidiaries and affiliates
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
General Partner Enterprise Products GP, LLC, the general partner of the Company and Operating
Partnership
Manta Ray A Gulf of Mexico offshore Louisiana natural gas pipeline system owned by Manta Ray
Offshore Gathering Company, LLC
MBFC Mississippi Business Finance Corporation
MBPD Thousand barrels per day
MLP Denotes Enterprise Products Partners L.P. as guarantor of certain debt obligations of
the Operating Partnership
MMBbls Millions of barrels
MMBtus Million British thermal units, a measure of heating value
MMcf Million cubic feet
MMcf/d Million cubic feet per day
MTBE Methyl tertiary butyl ether
Nautilus A Gulf of Mexico offshore Louisiana natural gas pipeline system owned by Nautilus
Pipeline Company, LLC
NGL or NGLs Natural gas liquid(s)
NYSE New York Stock Exchange
Operating Partnership Enterprise Products Operating L.P. and subsidiaries
Operating Surplus As defined within the Partnership Agreement
Partnership Agreement Second Amended and Restated Agreement of Limited Partnership of the Company
PTR Plant thermal reduction
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
Shell Shell Oil Company, its subsidiaries and affiliates
Subordination Period As defined within the Partnership Agreement
TNGL acquisition Refers to the acquisition of Tejas Natural Gas Liquids, LLC from Shell effective
August 1, 1999
PART 1. FINANCIAL INFORMATION.
Item 1. CONSOLIDATED FINANCIAL STATEMENTS.
Enterprise Products Partners L.P.
Consolidated Balance Sheets
(Dollar amounts in thousands)
June 30,
2001 December 31,
ASSETS (Unaudited) 2000
---------------------------------------
Current Assets
Cash and cash equivalents (includes restricted cash of $7,321 at June 30, $ 123,279 $ 60,409
2001)
Accounts receivable - trade, net of allowance for doubtful accounts of
$17,032 at June 30, 2001 and $10,916 at December 31, 2000 383,680 409,085
Accounts receivable - affiliates 9,011 6,533
Inventories 99,783 93,222
Prepaid and other current assets 79,260 12,107
---------------------------------------
Total current assets 695,013 581,356
Property, Plant and Equipment, Net 1,232,792 975,322
Investments in and Advances to Unconsolidated Affiliates 414,808 298,954
Intangible assets, net of accumulated amortization of $7,874 at
June 30, 2001 and $5,374 at December 31, 2000 90,369 92,869
Other Assets 9,011 2,867
---------------------------------------
Total $2,441,993 $1,951,368
=======================================
LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Accounts payable - trade $ 59,208 $ 96,559
Accounts payable - affiliate 51,266 56,447
Accrued gas payables 353,444 377,126
Accrued expenses 12,804 21,488
Other current liabilities 81,381 34,759
---------------------------------------
Total current liabilities 558,103 586,379
Long-Term Debt 855,608 403,847
Other Long-Term liabilities 17,260 15,613
Minority Interest 10,318 9,570
Commitments and Contingencies
Partners' Equity
Common Units (46,257,315 Units outstanding at June 30, 2001
and December 31, 2000) 565,469 514,896
Subordinated Units (21,409,870 Units outstanding at June 30, 2001
and December 31, 2000) 188,390 165,253
Special Units (16,500,000 Units outstanding at June 30, 2001
and December 31, 2000) 251,132 251,132
Treasury Units acquired by Trust, at cost (267,200 Common Units
outstanding at June 30, 2001 and December 31, 2000) (4,727) (4,727)
General Partner 10,151 9,405
Accumulated other comprehensive income (9,711)
---------------------------------------
Total Partners' Equity 1,000,704 935,959
---------------------------------------
Total $2,441,993 $1,951,368
=======================================
See Notes to Unaudited Consolidated Financial Statements
Page 1
Enterprise Products Partners L.P.
Statements of Consolidated Operations
(Unaudited)
(Amounts in thousands, except per Unit amounts)
Three Months Six Months
Ended June 30, Ended June 30,
------------------------------- -------------------------------
2001 2000 2001 2000
------------------------------- -------------------------------
REVENUES
Revenues from consolidated operations $959,397 $592,913 $1,795,712 $1,339,194
Equity income in unconsolidated affiliates 9,050 11,097 11,061 18,540
------------------------------- -------------------------------
Total 968,447 604,010 1,806,773 1,357,734
COST AND EXPENSES
Operating costs and expenses 851,639 546,306 1,629,380 1,219,212
Selling, general and administrative 7,737 7,658 13,905 13,042
------------------------------- -------------------------------
Total 859,376 553,964 1,643,285 1,232,254
------------------------------- -------------------------------
OPERATING INCOME 109,071 50,046 163,488 125,480
OTHER INCOME (EXPENSE)
Interest expense (16,331) (8,070) (23,318) (15,844)
Interest income from unconsolidated affiliates 7 126 31 270
Dividend income from unconsolidated affiliates 2,761 1,632 3,995
Interest income - other 1,479 1,225 5,477 2,706
Other, net (251) (62) (531) (425)
------------------------------- -------------------------------
Other income (expense) (15,096) (4,020) (16,709) (9,298)
------------------------------- -------------------------------
INCOME BEFORE MINORITY INTEREST 93,975 46,026 146,779 116,182
MINORITY INTEREST (944) (466) (1,478) (1,175)
------------------------------- -------------------------------
NET INCOME $ 93,031 $ 45,560 $ 145,301 $ 115,007
=============================== ===============================
ALLOCATION OF NET INCOME TO:
Limited partners $ 91,643 $ 45,104 $ 142,931 $ 113,857
=============================== ===============================
General partner $ 1,388 $ 456 $ 2,370 $ 1,150
=============================== ===============================
BASIC EARNINGS PER UNIT
Income before minority interest $ 1.37 $ 0.68 $ 2.13 $ 1.72
=============================== ===============================
Net income per Common and Subordinated unit $ 1.35 $ 0.68 $ 2.11 $ 1.71
=============================== ===============================
DILUTED EARNINGS PER UNIT
Income before minority interest $ 1.10 $ 0.56 $ 1.72 $ 1.42
=============================== ===============================
Net income per Common, Subordinated
and Special unit $ 1.09 $ 0.56 $ 1.70 $ 1.40
=============================== ===============================
See Notes to Unaudited Consolidated Financial Statements
Page 2
Enterprise Products Partners L.P
Statements of Consolidated Cash Flows
(Unaudited)
(Dollar amounts in Thousands)
Six Months Ended
June 30,
-------------------------------------
2001 2000
-------------------------------------
OPERATING ACTIVITIES
Net income $145,301 $115,007
Adjustments to reconcile net income to cash flows provided by
(used for) operating activities:
Depreciation and amortization 23,234 18,347
Equity in income of unconsolidated affiliates (11,061) (18,540)
Distributions received from unconsolidated affiliates 13,212 14,268
Leases paid by EPCO 5,267 5,270
Minority interest 1,478 1,175
Gain (loss) on sale of assets (387) 2,303
Changes in fair market value of financial instruments (see Note 10) (55,880)
Net effect of changes in operating accounts (30,569) 57,003
-------------------------------------
Operating activities cash flows 90,595 194,833
-------------------------------------
INVESTING ACTIVITIES
Capital expenditures (57,090) (154,246)
Proceeds from sale of assets 563 52
Business acquisitions, net of cash received (225,665)
Collection of notes receivable from unconsolidated affiliates 6,519
Investments in and advances to unconsolidated affiliates (115,282) (3,040)
-------------------------------------
Investing activities cash flows (397,474) (150,715)
-------------------------------------
FINANCING ACTIVITIES
Long-term debt borrowings 449,716 463,818
Long-term debt repayments (355,000)
Debt issuance costs (3,125) (2,759)
Cash dividends paid to partners (76,112) (67,639)
Cash dividends paid to minority interest by Operating Partnership (783) (690)
Cash contributions from EPCO to minority interest 53 57
Increase in restricted cash (7,321)
-------------------------------------
Financing activities cash flows 362,428 37,787
-------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS 55,549 81,905
CASH AND CASH EQUIVALENTS, JANUARY 1 60,409 5,230
-------------------------------------
CASH AND CASH EQUIVALENTS, JUNE 30 $115,958 $ 87,135
=====================================
See Notes to Unaudited Consolidated Financial Statements
Page 3
Enterprise Products Partners L.P.
Statements of Consolidated Partners' Equity and
Comprehensive Income
(Unaudited, amounts in thousands)
Partners' Equity
----------------------------------------------------------------------------
at June 30, 2001 at June 30, 2000
------------------------------------- -------------------------------------
Units Amount Units Amount
------------------------------------- -------------------------------------
Limited Partners
Balance, beginning of year 84,434 $ 931,281 81,463 $786,250
Net income 142,931 113,857
Leases paid by EPCO 5,213 5,218
Cash distributions (74,434) (66,964)
------------------------------------- -------------------------------------
Balance, end of period 84,434 1,004,991 81,463 838,361
------------------------------------- -------------------------------------
------------------------------------- -------------------------------------
Treasury Units (267) (4,727) (267) (4,727)
------------------------------------- -------------------------------------
General Partner
Balance, beginning of year 9,405 7,942
Net income 2,370 1,150
Leases paid by EPCO 54 53
Cash distributions (1,678) (676)
------------------- ------------------
Balance, end of period 10,151 8,469
------------------- ------------------
Accumulated Other
Comprehensive Loss
Balance, beginning of year
Cumulative transition adjustment
recorded on January 1, 2001
upon adoption of SFAS 133 (42,190)
(see Note 10)
Reclassification of cumulative
transition adjustment to
earnings 32,479
-------------------
Balance, end of period (9,711)
-------------------
------------------------------------- -------------------------------------
Total Partners' Equity 84,167 $1,000,704 81,196 $842,103
===================================== =====================================
Comprehensive Income
For Six Months Ended
----------------------------------------------------------------------------
at June 30, 2001 at June 30, 2000
------------------------------------- -------------------------------------
Net Income $145,301 $115,007
Less: Accumulated Other
Comprehensive Loss (9,711)
------------------- ------------------
Comprehensive Income $135,590 $115,007
=================== ==================
See Notes to Unaudited Consolidated Financial Statements
Page 4
Enterprise Products Partners L.P.
Notes to Unaudited Consolidated Financial Statements
1. GENERAL
In the opinion of Enterprise Products Partners L.P. (the "Company"), the accompanying unaudited consolidated
financial statements include all adjustments consisting of normal recurring accruals necessary for a fair
presentation of the Company's consolidated financial position as of June 30, 2001 and consolidated results of
operations, cash flows, partners' equity and comprehensive income for the three and six month periods ended June
30, 2001 and 2000. Although the Company believes the disclosures in these financial statements are adequate to
make the information presented not misleading, certain information and footnote disclosures normally included in
annual financial statements prepared in accordance with generally accepted accounting principles have been
condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission. These
unaudited financial statements should be read in conjunction with the financial statements and notes thereto
included in the Company's annual report on Form 10-K (File No. 1-14323) for the year ended December 31, 2000.
The preparation of financial statements in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the
date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
The results of operations for the three and six month periods ended June 30, 2001 are not necessarily indicative
of the results to be expected for the full year due to the effects of, among other things, (a) seasonal
variations in NGL and natural gas prices, (b) timing of maintenance and other expenditures and (c) acquisitions
of assets and other interests.
Certain reclassifications have been made to prior years' financial statements to conform to the presentation of
the current period financial statements. These reclassifications do not affect historical earnings of the
Company.
Dollar amounts presented in the tabulations within the notes to the consolidated financial statements are stated
in thousands of dollars, unless otherwise indicated.
2. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES
The Company owns interests in a number of related businesses that are accounted for under the equity method or
cost method. The investments in and advances to these unconsolidated affiliates are grouped according to the
operating segment to which they relate. For a general discussion of the Company's business segments, see Note
11.
At June 30, 2001, the Company's equity method investments (grouped by operating segment) included:
Fractionation segment:
o Baton Rouge Fractionators LLC ("BRF") - an approximate 32.25% interest in a natural gas liquid ("NGL")
fractionation facility located in southeastern Louisiana.
o Baton Rouge Propylene Concentrator, LLC ("BRPC") - a 30.0% interest in a propylene concentration unit
located in southeastern Louisiana.
o K/D/S Promix LLC ("Promix") - a 33.33% interest in a NGL fractionation facility and related storage
facilities located in south Louisiana. The Company's investment includes excess cost over the underlying
equity in the net assets of Promix of $8.0 million which is being amortized using the straight-line method
over a period of 20 years. The unamortized balance of excess cost over the underlying equity in the net
assets of Promix was $7.2 million at June 30, 2001.
Page 5
Pipeline segment:
o EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively, "EPIK") - a 50% aggregate interest in a
refrigerated NGL marine terminal loading facility located in southeast Texas.
o Wilprise Pipeline Company, LLC ("Wilprise") - a 37.35% interest in a NGL pipeline system located in
southeastern Louisiana.
o Tri-States NGL Pipeline LLC ("Tri-States") - an aggregate 33.33% interest in a NGL pipeline system
located in Louisiana, Mississippi, and Alabama.
o Belle Rose NGL Pipeline LLC ("Belle Rose") - a 41.67% interest in a NGL pipeline system located in
south Louisiana.
o Dixie Pipeline Company ("Dixie") - a 19.9% interest in a 1,301-mile propane pipeline and associated
facilities extending from Mont Belvieu, Texas to North Carolina.
o Starfish Pipeline Company LLC ("Starfish") - a 50% interest in a natural gas gathering system and
related dehydration and other facilities located in south Louisiana and the Gulf of Mexico offshore
Louisiana.
o Ocean Breeze Pipeline Company LLC ("Ocean Breeze") - a 25.67% interest in a limited liability company
("LLC") owning a 1% interest in the natural gas gathering and transmission systems owned by Manta Ray
Offshore Gathering Company, LLC ("Manta Ray") and Nautilus Pipeline Company LLC ("Nautilus") located in the
Gulf of Mexico offshore Louisiana.
o Neptune Pipeline Company LLC ("Neptune") - a 25.67% interest in a limited liability company owning a 99%
interest in the Manta Ray and Nautilus natural gas gathering and transmission systems.
o Nemo Gathering Company, LLC ("Nemo") - a 33.92% interest in a natural gas gathering system being
constructed in the Gulf of Mexico offshore Louisiana. The system is scheduled for completion during the
third quarter of 2001.
o Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp. (collectively, "Evangeline") - an
approximate 49.5% aggregate interest in a natural gas pipeline system located in south Louisiana. The
Company acquired its interests in these entities as a result of the Acadian Gas, LLC acquisition (see Note 3
for a description of this acquisition).
2001 Gulf of Mexico natural gas pipeline equity investments
The Company acquired its equity interests in Ocean Breeze, Neptune, Nemo and Starfish and their underlying
investments on January 29, 2001 from EPE using proceeds from the issuance of the $450 Million Senior Notes
(see Note 5 for discussion of long-term debt). The cash purchase price of the Ocean Breeze, Neptune and
Nemo interests was $86.9 million with the purchase price of the Starfish interests being $25.1 million.
As a result of its investment in Ocean Breeze and Neptune, the Company acquired a 25.67% interest in each of
the Manta Ray and Nautilus systems and a 33.92% interest in the Nemo system. Affiliates of Shell own an
interest in all three systems, and an affiliate of Marathon Oil Company owns an interest in the Manta Ray
and Nautilus systems. The Manta Ray system comprises approximately 225 miles of pipeline with a capacity
of 750 MMcf/d and related equipment, the Nautilus system comprises approximately 101 miles of pipeline with
a capacity of 600 MMcf/d, and the Nemo system, when completed in the third quarter of 2001, will comprise
approximately 24 miles of pipeline with a capacity of 300 MMcf/d. Shell is responsible for the commercial
and physical operations of these pipeline systems.
The Company's investment in Ocean Breeze and Neptune includes excess cost over the underlying equity in the
net assets of these entities of $22.7 million which is being amortized using the straight-line method over a
period of 35 years (as a pipeline asset). The unamortized balance of excess cost over the underlying
equity in the net assets of Ocean Breeze and Neptune was $22.4 million at June 30, 2001. Likewise, the
Company's investment in Nemo includes excess cost over the underlying equity in the net assets of $0.8
million which will be amortized using the straight-line method over a period of 35 years (as a pipeline
asset) when Nemo becomes operational during the third quarter of 2001.
As a result of its investment in Starfish, the Company acquired a 50% interest in the Stingray system and a
related onshore natural gas dehydration facility. The Company's sole partner in Starfish is an affiliate of
Shell. The Stingray system comprises approximately 375 miles of pipeline with a capacity of 1.2 Bcf per
Page 6
day and is located offshore Louisiana in the Gulf of Mexico. Shell is responsible for the commercial and
physical operations of the Stingray system and related facilities.
Historical information for periods prior to January 1, 2001 do not reflect any impact associated with the
Company's equity investments in Ocean Breeze, Neptune, Nemo and Starfish. See Note 3 for combined pro
forma impact of these investments on selected financial information of the Company.
Octane Enhancement segment:
o Belvieu Environmental Fuels ("BEF") - a 33.33% interest in a MTBE production facility located in
southeast Texas. The production of MTBE is driven by oxygenated fuels programs enacted under the federal
Clean Air Act Amendments of 1990 and other legislation. Any changes to these programs that enable
localities to elect not to participate in these programs, lessen the requirements for oxygenates or favor
the use of non-isobutane based oxygenated fuels reduce the demand for MTBE and could have an adverse effect
on the Company's results of operations.
In recent years, MTBE has been detected in water supplies. The major source of the ground water
contamination appears to be leaks from underground storage tanks. Although these detections have been
limited and the great majority have been well below levels of public health concern, there have been calls
for the phase-out of MTBE in motor gasoline in various federal and state governmental agencies and advisory
bodies.
In light of these developments, the owners of BEF have been formulating a contingency plan for use of the
BEF facility if MTBE were banned or significantly curtailed. Management is exploring a possible conversion
of the BEF facility from MTBE production to alkylate production. Depending upon the type of alkylate
process chosen and the level of alkylate production desired, the cost to convert the facility from MTBE
production to alkylate production can range from $20 million to $90 million, with the Company's share of
these costs ranging from $6.7 million to $30 million.
At June 30, 2001, the Company's investments in and advances to unconsolidated affiliates also includes Venice
Energy Services Company, LLC ("VESCO"). The VESCO investment consists of a 13.1% interest in a LLC owning a
natural gas processing plant, fractionation facilities, storage, and gas gathering pipelines in Louisiana. This
investment is accounted for using the cost method under the Processing segment.
Page 7
The following table summarizes investments in and advances to unconsolidated affiliates at:
June 30, December 31,
2001 2000
-------------------------------------
Accounted for on equity basis:
Fractionation:
BRF $ 30,210 $ 30,599
BRPC 19,638 25,925
Promix 48,214 48,670
Pipeline:
EPIK 15,467 15,998
Wilprise 8,617 9,156
Tri-States 27,238 27,138
Belle Rose 11,591 11,653
Dixie 38,179 38,138
Starfish 26,763
Ocean Breeze 960
Neptune 76,282
Nemo 10,814
Evangeline 5,574
Octane Enhancement:
BEF 62,261 58,677
Accounted for on cost basis:
Processing:
VESCO 33,000 33,000
-------------------------------------
Total $414,808 $298,954
=====================================
The following table shows equity in income (loss) of unconsolidated affiliates for the periods indicated:
For Three Months Ended For Six Months Ended
June 30, June 30,
------------------------------------- -------------------------------------
2001 2000 2001 2000
------------------------------------- -------------------------------------
Fractionation:
BRF $ 42 $ 208 $ 60 $ 737
BRPC 252 (29) 404 (19)
Promix 1,396 1,546 1,789 3,208
Pipeline:
EPIK (172) 178 (1,094) 1,970
Wilprise 85 74 (137) 162
Tri-States 135 843 100 1,521
Belle Rose 29 (30) (60) 149
Dixie 69 960
Starfish 1,022 1,973
Ocean Breeze 12 14
Neptune 1,095 1,789
Nemo 1 10
Evangeline (149) (149)
Octane Enhancement:
BEF 5,233 8,307 5,402 10,812
------------------------------------- -------------------------------------
Total $9,050 $11,097 $11,061 $18,540
===================================== =====================================
Page 8
The following table presents summarized income statement information for the unconsolidated affiliates accounted
for by the equity method for the periods indicated (on a 100% basis):
Summarized Income Statement data for the Six Months ended
-----------------------------------------------------------------------------------------------
June 30, 2001 June 30, 2000
---------------------------------------------- -----------------------------------------------
Operating Net Operating Net
Revenues Income Income Revenues Income Income
---------------------------------------------- -----------------------------------------------
Fractionation:
BRF $ 7,825 $ 300 $ 350 $ 9,215 $ 2,222 $ 2,284
BRPC 6,833 1,232 1,347 (187) (65)
Promix 21,343 5,888 5,964 24,726 10,141 10,255
Pipeline:
EPIK 1,967 (1,782) (1,725) 12,972 3,884 3,981
Wilprise 893 (378) (367) 1,423 470 485
Tri-States 3,953 262 299 7,247 4,470 4,562
Belle Rose 554 (205) (192) 1,266 366 366
Dixie (a) 24,036 8,301 4,829
Starfish (b) 13,467 4,390 3,916
Ocean Breeze (b) 87 87 65
Neptune (b) 16,747 8,648 8,581
Nemo (b) (42) 36
Evangeline (c) 47,609 1,010 (144)
Octane Enhancement:
BEF 113,918 15,922 16,207 137,430 32,373 32,437
---------------------------------------------- -----------------------------------------------
Total $259,232 $43,633 $39,166 $194,279 $53,739 $54,305
============================================== ===============================================
Summarized Income Statement data for the Three Months ended
-----------------------------------------------------------------------------------------------
June 30, 2001 June 30, 2000
---------------------------------------------- -----------------------------------------------
Operating Net Operating Net
Revenues Income Income Revenues Income Income
---------------------------------------------- -----------------------------------------------
Fractionation:
BRF $ 3,802 $ 265 $ 294 $ 4,244 $ 569 $ 648
BRPC 3,400 793 842 (187) (99)
Promix 12,340 4,447 4,487 12,517 4,752 4,809
Pipeline:
EPIK 792 (375) (348) 3,816 324 387
Wilprise 494 224 227 691 212 222
Tri-States 2,321 388 403 3,513 2,490 2,527
Belle Rose 407 13 21 409 (64) (64)
Dixie (a) 8,799 2,001 1,124
Starfish (b) 7,051 2,571 2,299
Ocean Breeze (b) 53 39 39
Neptune (b) 9,362 5,223 5,195
Nemo (b) (27) 2
Evangeline (c) 47,609 1,010 (144)
Octane Enhancement:
BEF 76,054 15,509 15,700 84,097 24,766 24,921
---------------------------------------------- -----------------------------------------------
Total $172,484 $32,081 $30,141 $109,287 $32,862 $33,351
============================================== ===============================================
Page 9
Notes to Summarized Income Statement data tables:
(a) Dixie became an equity method investment in October 2000.
(b) These entities became equity method investments of the Company beginning in January 2001.
(c) This entity became an equity method investment of the Company in April 2001 as a result of the Acadian Gas
acquisition (see Note 3).
3. ACQUISITIONS
Since January 1, 2001, the Company has invested approximately $338 million (net of cash acquired) in natural gas
pipeline businesses. These include:
o a combined $112 million in Ocean Breeze, Neptune, Nemo and Starfish (see Note 2 for a discussion of
these equity investments); and,
o an initial $226 million for the purchase of Acadian Gas, LLC ("Acadian Gas").
Acquisition of Acadian Gas
On April 2, 2001, the Company acquired Acadian Gas from Shell US Gas and Power LLC, an affiliate of Shell, for
approximately $226 million in cash using proceeds from the issuance of the $450 Million Senior Notes. The cash
purchase price is subject to certain post-closing adjustments expected to be completed during the third quarter
of 2001 (see below). The effective date of the transaction was April 1, 2001.
Acadian Gas is involved in the purchase, sale, transportation and storage of natural gas in Louisiana. Acadian
Gas' assets are comprised of the 438-mile Acadian, 577-mile Cypress and 27-mile Evangeline natural gas pipeline
systems, which together have over 1.1 Bcf/d of capacity. These natural gas pipeline systems are wholly-owned by
Acadian Gas with the exception of the Evangeline system in which Acadian Gas owns an aggregate 49.5% interest.
The assets acquired include a leased natural gas storage facility located in Napoleonville, Louisiana.
The Acadian, Cypress and Evangeline systems link supplies of natural gas from onshore developments and, through
connections with offshore pipelines, Gulf of Mexico production to local gas distribution companies, electric
generation and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor.
In addition, these systems have interconnects with 12 interstate and four intrastate pipelines and a
bi-directional interconnect with the U.S. natural gas marketplace at Henry Hub.
The Acadian Gas acquisition was accounted for under the purchase method of accounting and, accordingly, the
initial purchase price has been allocated to the assets acquired and liabilities assumed based on their estimated
fair values at April 1, 2001, as follows:
Current assets $83,123
Investments in unconsolidated affiliates 2,723
Property, plant and equipment 220,856
Current liabilities (79,577)
Other long-term liabilities (1,460)
---------------
Total purchase price $225,665
===============
The balances related to the Acadian Gas acquisition included in the consolidated balance sheet dated June 30,
2001 are based upon preliminary information and are subject to change as additional information is obtained. As
noted earlier, the initial purchase price is subject to certain post-closing adjustments attributable to working
capital items expected to be finalized during the third quarter of 2001.
Historical information for periods prior to April 1, 2001 do not reflect any impact associated with the Acadian
Gas acquisition.
Page 10
Pro Forma effect of Acadian Gas acquisition and recently acquired equity investments
The following table presents selected unaudited pro forma information for the three month period ended June 30,
2000 and six month periods ended June 30, 2001 and 2000 as if the acquisition of the Acadian Gas natural gas
pipeline systems had been made as of the beginning of the years presented. This table also incorporates selected
unaudited pro forma information for the three and six month periods ended June 30, 2000 relating to the Company's
equity investments in Starfish, Ocean Breeze and Neptune.
The pro forma information is based upon information currently available to and certain estimates and assumptions
by management and, as a result, are not necessarily indicative of the financial results of the Company had the
transactions actually occurred on these dates. Likewise, the unaudited pro forma information is not necessarily
indicative of future financial results of the Company.
Three Months Six Months Ended
Ended June 30,
------------------------------------
June 30, 2000 2001 2000
-------------------------------------------------------
Revenues $756,769 $2,018,700 $1,608,252
=======================================================
Income before extraordinary item
and minority interest $ 45,502 $151,063 $ 115,187
=======================================================
Net income $ 45,041 $149,542 $ 114,022
=======================================================
Allocation of net income to
Limited partners $ 44,590 $147,130 $ 112,881
=======================================================
General Partner $ 450 $ 2,412 $ 1,140
=======================================================
Units used in earnings per Unit calculations
Basic 66,696 67,667 66,696
=======================================================
Diluted 81,196 84,167 81,196
=======================================================
Income per Unit before minority interest
Basic $ 0.68 $ 2.20 $ 1.71
=======================================================
Diluted $ 0.56 $ 1.77 $ 1.40
=======================================================
Net income per Unit
Basic $ 0.67 $ 2.17 $ 1.69
=======================================================
Diluted $ 0.55 $ 1.75 $ 1.39
=======================================================
4. RECENTLY ISSUED ACCOUNTING STANDARDS
In June 2001, the FASB issued two new pronouncements: SFAS No. 141, " Business Combinations", and SFAS No. 142,
"Goodwill and Other Intangible Assets". SFAS No. 141 prohibits the use of the pooling-of-interest method for
business combinations initiated after June 30, 2001 and also applies to all business combinations accounted for
by the purchase method that are completed after June 30, 2001. There are also transition provisions that apply
to business combinations completed before July 1, 2001, that were accounted for by the purchase method. SFAS 142
is effective for fiscal years beginning after December 15, 2001 to all goodwill and other intangible assets
recognized in an entity's statement of financial position at that date, regardless of when those assets were
Page 11
initially recognized. The Company is currently evaluating the provisions of SFAS 141 and SFAS 142 and has not
adopted such provisions in its June 30, 2001 financial statements.
5. LONG-TERM DEBT
Long-term debt consisted of the following at:
June 30, December 31,
2001 2000
---------------------------------------
Borrowings under:
$350 Million Senior Notes, 8.25% fixed rate, due March 2005 350,000 350,000
$54 Million MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000
$450 Million Senior Notes, 7.50% fixed rate, due February 2011 450,000
------------------------------------
Total principal amount 854,000 404,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt 2,015
Less unamortized discount on:
$350 Million Senior Notes (135) (153)
$450 Million Senior Notes (272)
Less current maturities of long-term debt
------------------------------------
Long-term debt $855,608 $403,847
=======================================
The Company has the ability to borrow under the terms of its $250 Million Multi-Year Credit Facility and $150
Million 364-Day Credit Facility. No amount was outstanding under either of these two revolving credit
facilities at June 30, 2001 or December 31, 2000.
At June 30, 2001, the Company had a total of $75 million of standby letters of credit capacity under its $250
Million Multi-Year Credit Facility of which $19.9 million was outstanding.
$450 Million Senior Notes. On January 24, 2001, a subsidiary of the Company completed a public offering of $450
million in principal amount of 7.50% fixed-rate Senior Notes due February 1, 2011 at a price to the public of
99.937% per Senior Note (the "$450 Million Senior Notes"). The Company received proceeds, net of underwriting
discounts and commissions, of approximately $446.8 million. The proceeds from this offering were used to
acquire the Acadian Gas, Ocean Breeze, Neptune, Nemo and Starfish natural gas pipeline systems for $338 million
and to finance the cost to construct certain NGL pipelines and related projects and for working capital and other
general partnership purposes.
The $450 Million Senior Notes were issued under the indenture agreement dated March 15, 2000 which is also
applicable to the $350 Million Senior Notes and therefore are subject to similar covenants and terms. As with
the $350 Million Senior Notes, the $450 Million Senior Notes:
o are subject to a make-whole redemption right;
o are an unsecured obligation and rank equally with existing and future unsecured and unsubordinated
indebtedness and senior to any future subordinated indebtedness; and,
o are guaranteed by the Company through an unsecured and unsubordinated guarantee.
The issuance of the $450 Million Senior Notes was a final takedown under the December 1999 $800 million
universal registration statement; therefore, the amount of securities available under this registration statement
was reduced to zero. On February 23, 2001, the Company filed a $500 million universal shelf registration
statement (the "February 2001 Registration Statement") covering the issuance of an unspecified amount of equity
or debt securities or a combination thereof. The Company expects to use the net proceeds from any sale of
securities under the February 2001 Registration Statement for future business acquisitions and other general
Page 12
corporate purposes, such as working capital, investments in subsidiaries, the retirement of existing debt and/or
the repurchase of Common Units or other securities. The exact amounts to be used and when the net proceeds will
be applied to partnership purposes will depend on a number of factors, including the Company's funding
requirements and the availability of alternative funding sources. The Company routinely reviews acquisition
opportunities.
The Company was in compliance with the restrictive covenants associated with all of its fixed-rate and
variable-rate debt instruments at June 30, 2001.
Increase in fair value of fixed-rate debt. Upon adoption of SFAS 133, Accounting for Derivative Instruments and
Hedging Activities (as amended and interpreted) on January 1, 2001, the Company recorded a $2.3 million non-cash
increase in the fair value of its fixed-rate debt. SFAS 133 required that the Company's interest rate swaps and
their associated hedged fixed-rate debt be recorded at fair value upon adoption of the standard. After adoption
of the standard, the interest rate swaps were dedesignated due to differences in the estimated maturity dates of
the interest rate swaps versus the fixed-rate debt. As a result, the fair value of the hedged fixed-rate debt
will not be adjusted for future changes in fair value and the $2.3 million increase in the fair value of the debt
will be amortized to earnings over the remaining life of the fixed-rate debt to which it applies, which
approximates 10 years. The fair value adjustment of $2.3 million is not a cash obligation of the Company and
does not alter the amount of the Company's indebtedness. See Note 10 for additional information concerning the
Company's financial instruments.
6. CAPITAL STRUCTURE
Final issue of Special Units. On or about June 30, 2001, Shell met certain year 2001 performance criteria for
the issuance of the last installment of 3.0 million non-distribution bearing, convertible Contingency Units
(referred to as Special Units once they are issued). Per a contingent unit agreement with Shell, the Company
issued these Special Units on August 2, 2001.
The value of these Special Units was determined to be $117.1 million using present value techniques. This
amount will increase the purchase price of the TNGL acquisition and the value of the Shell Processing Agreement
when the issue is recorded during the third quarter of 2001. The $117.1 million increase in value of the Shell
Processing Agreement will be amortized over the remaining life of the contract. As a result, amortization
expense will increase by approximately $1.6 million per quarter ($6.5 million annually).
Conversion of Special Units to Common Units. In accordance with existing agreements with Shell, 5.0 million of
Shell's original issue of Special Units converted into Common Units on August 2, 2001.
Page 13
7. EARNINGS PER UNIT
Basic earnings per Unit is computed by dividing net income available to limited partner interests by the
weighted-average number of Common and Subordinated Units outstanding during the period. Diluted earnings per
Unit is computed by dividing net income available to limited partner interests by the weighted-average number of
Common, Subordinated and Special Units outstanding during the period. The following table reconciles the
number of shares used in the calculation of basic earnings per Unit and diluted earnings per Unit for the three
and six months ended June 30, 2001 and 2000:
For Three Months Ended For Six Months Ended
June 30, June 30,
------------------------------------- ------------------------------------
2001 2000 2001 2000
------------------------------------- ------------------------------------
Income before minority interest $93,975 $46,026 $146,779 $116,182
General partner interest (1,388) (456) (2,370) (1,150)
------------------------------------- ------------------------------------
Income before minority interest 92,587 45,570 144,409 115,032
available to Limited Partners
Minority interest (944) (466) (1,478) (1,175)
------------------------------------- ------------------------------------
Net income available to Limited Partners $91,643 $45,104 $142,931 $113,857
===================================== ====================================
BASIC EARNINGS PER UNIT
Numerator
Income before minority interest
available to Limited Partners $92,587 $45,570 $144,409 $115,032
Net income available
to Limited Partners $91,643 $45,104 $142,931 $113,857
Denominator
Common Units outstanding 46,257 45,286 46,257 45,286
Subordinated Units outstanding 21,410 21,410 21,410 21,410
------------------------------------- ------------------------------------
Total 67,667 66,696 67,667 66,696
===================================== ====================================
Basic Earnings per Unit
Income before minority interest
available to Limited Partners $ 1.37 $ 0.68 $ 2.13 $ 1.72
===================================== ====================================
Net income available
to Limited Partners $ 1.35 $ 0.68 $ 2.11 $ 1.71
===================================== ====================================
DILUTED EARNINGS PER UNIT
Numerator
Income before minority interest
available to Limited Partners $92,587 $45,570 $144,409 $115,032
Net income available
to Limited Partners $91,643 $45,104 $142,931 $113,857
Denominator
Common Units outstanding 46,257 45,286 46,257 45,286
Subordinated Units outstanding 21,410 21,410 21,410 21,410
Special Units outstanding 16,500 14,500 16,500 14,500
------------------------------------- ------------------------------------
Total 84,167 81,196 84,167 81,196
===================================== ====================================
Diluted Earnings per Unit
Income before minority interest
available to Limited Partners $ 1.10 $ 0.56 $ 1.72 $ 1.42
===================================== ====================================
Net income available
to Limited Partners $ 1.09 $ 0.56 $ 1.70 $ 1.40
===================================== ====================================
Page 14
8. DISTRIBUTIONS
The Company intends, to the extent there is sufficient available cash from Operating Surplus, as defined by the
Partnership Agreement, to distribute to each holder of Common Units at least a minimum quarterly distribution of
$0.45 per Common Unit. The minimum quarterly distribution is not guaranteed and is subject to adjustment as set
forth in the Partnership Agreement. With respect to each quarter during the Subordination Period, the Common
Unitholders will generally have the right to receive the minimum quarterly distribution, plus any arrearages
thereon, and the General Partner will have the right to receive the related distribution on its interest before
any distributions of available cash from Operating Surplus are made to the Subordinated Unitholders. As an
incentive, the General Partner's interest in quarterly distributions is increased after certain specified target
levels are met. The Company made incentive cash distributions to the General Partner of $0.5 million and $0.9
million during the three and six months ended June 30, 2001 and none during the same periods in 2000.
On January 17, 2000, the Company declared an increase in its quarterly cash distribution to $0.50 per Unit.
This amount was subsequently raised to $0.525 per Unit on July 17, 2000 and $0.55 per Unit on December 7, 2000.
On May 3, 2001, the Board of Directors of the General Partner approved an increase in the quarterly distribution
rate to $.5875 per Unit beginning with the distribution pertaining to the second quarter of 2001 (payable in
August 2001).
The following is a summary of cash distributions to partnership interests since the first quarter of 1999:
Cash Distributions
--------------------------------------------------------------------
Per
Per Common Subordinated Record Payment
Unit Unit Date Date
--------------------------------------------------------------------
1999 First Quarter $ 0.450 $ 0.450 Jan. 29, 1999 Feb. 11, 1999
Second Quarter $ 0.450 $ 0.070 Apr. 30, 1999 May 12, 1999
Third Quarter $ 0.450 $ 0.370 Jul. 30, 1999 Aug. 11, 1999
Fourth Quarter $ 0.450 $ 0.450 Oct. 29, 1999 Nov. 10, 1999
2000 First Quarter $ 0.500 $ 0.500 Jan. 31, 2000 Feb. 10, 2000
Second Quarter $ 0.500 $ 0.500 Apr. 28, 2000 May 10, 2000
Third Quarter $ 0.525 $ 0.525 Jul. 31, 2000 Aug. 10, 2000
Fourth Quarter $ 0.525 $ 0.525 Oct. 31, 2000 Nov. 10, 2000
2001 First Quarter $ 0.550 $ 0.550 Jan. 31, 2001 Feb. 9, 2001
Second Quarter $ 0.550 $ 0.550 Apr. 30, 2001 May 10, 2001
Third Quarter $ 0.5875 $ 0.5875 Jul. 31, 2001 Aug. 10, 2001
(through August 13, 2001)
Page 15
9. SUPPLEMENTAL CASH FLOW DISCLOSURE
The net effect of changes in operating assets and liabilities is as follows for the periods indicated:
Six Months Ended
June 30,
------------------------------------------
2001 2000
------------------------------------------
(Increase) decrease in:
Accounts receivable $ 96,860 $ 66,374
Inventories 522 (104,477)
Prepaid and other current assets (10,831) 3,154
Intangible assets (3,736)
Other assets (129) (1,890)
Increase (decrease) in:
Accounts payable (55,755) (64,675)
Accrued gas payable (78,008) 168,683
Accrued expenses (11,232) (11,698)
Other current liabilities 27,817 5,904
Other liabilities 187 (636)
------------------------------------------
Net effect of changes in operating accounts $(30,569) $ 57,003
==========================================
Business acquisitions (net of cash received) for the 2001 period reflects a net $226 million paid to an affiliate
of Shell for Acadian Gas. Investments in and advances to unconsolidated affiliates for the 2001 period reflects
$112 million paid to EPE for equity interests in various Gulf of Mexico natural gas pipeline systems. Capital
expenditures for 2000 included $99.5 million for the purchase of the Lou-Tex Propylene Pipeline and related
assets.
As a result of the Company's adoption of SFAS 133 on January 1, 2001, the Company records various financial
instruments relating to interest rate and commodity positions at their respective fair values. For the six
months ended June 30, 2001, the Company recognized a net $55.9 million in non-cash mark-to-market gains related
to increases in the fair value of these financial instruments ($52.5 million of this amount was attributable to
commodity financial instruments with the remainder resulting from interest rate hedging activities). See Note
10 below for a further description of the Company's financial instruments.
Cash and cash equivalents at June 30, 2001 per the Statements of Consolidated Cash Flows excludes $7.3 million of
restricted cash associated with commodity hedging activities.
10. FINANCIAL INSTRUMENTS
The Company holds and issues financial instruments for the purpose of hedging the risks of certain identifiable
and anticipated transactions. In general, the types of risks hedged are those relating to the variability of
future earnings and cash flows caused by changes in commodity prices and interest rates.
Commodity Financial Instruments - Gas Processing and related NGL and natural gas businesses
The Company is exposed to commodity price risk through its natural gas processing and related NGL and natural gas
businesses. In order to effectively manage this risk, the Company may enter into swaps, forwards, commodity
futures, options and other commodity financial instruments with similar characteristics that are permitted by
contract or business custom to be settled in cash or with another financial instrument. The purpose of these
risk management activities is to hedge exposure to price risks associated with natural gas, NGL production and
inventories, firm commitments and certain anticipated transactions.
The Company has adopted a commercial policy to manage its exposure to the risks generated by its gas processing
and related NGL and natural gas businesses. The objective of this policy is to assist the Company in achieving
Page 16
its profitability goals while maintaining a portfolio of conservative risk, defined as remaining within the
position limits established by the General Partner. The Company enters into risk management transactions to
manage price risk, basis risk, physical risk, or other risks related to the energy commodities on both a
short-term (less than 30 days) and long-term basis, not to exceed 18 months. The General Partner oversees the
strategies of the Company associated with physical and financial risks, approves specific activities of the
Company subject to the policy (including authorized products, instruments and markets) and establishes specific
guidelines and procedures for implementing and ensuring compliance with the policy.
On January 1, 2001, the Company adopted SFAS 133 which required the Company to record the fair market value of
the commodity financial instruments on the balance sheet based upon then current market conditions. The fair
market value of the then outstanding commodity financial instruments was a net liability of $42.2 million (the
"cumulative transition adjustment") with an offsetting equal amount recorded in Other Comprehensive Income. The
amounts in Other Comprehensive Income are reclassified to earnings in the accounting period associated with the
hedged transaction (e.g. production month). The $42.2 million cumulative transition adjustment was or will be
reclassified to earnings as follows:
o $21.7 million during the first quarter of 2001;
o $10.7 million during the second quarter of 2001;
o $7.3 million during the third quarter of 2001; with the remaining
o $2.5 million reclassified during the fourth quarter of 2001.
The amounts recorded in Other Comprehensive Income at adoption of SFAS 133 will not be adjusted for changes in
fair value; rather, any change in the fair value of these commodity financial instruments will be recorded in
earnings (i.e., mark-to-market accounting treatment). The decision to record changes in the fair value of
these commodity financial instruments directly to earnings rather than Other Comprehensive Income is based upon
the determination by management that on an ongoing basis these commodity financial instruments would be
ineffective under the guidelines of SFAS 133.
The Company has entered into commodity financial instruments for time periods extending through June 2002. These
commodity financial instruments may not qualify for hedge accounting treatment under the specific guidelines of
SFAS 133. The Company continues to refer to these financial instruments as hedges in as much as this was the
intent when such contracts were executed. This characterization is consistent with the actual economic
performance of the contracts and the Company expects these financial instruments to continue to mitigate
commodity price risk in the future. The specific accounting for these contracts, however, is consistent with
the requirements of SFAS 133. As such, since these contracts do not qualify for hedge accounting under the
specific guidelines of SFAS 133, the change in fair value of these commodity financial instruments will be
reflected on the balance sheet and in earnings (i.e., mark-to-market accounting treatment).
The following table shows the impact of commodity financial instruments on earnings for the three and six months
ended June 30, 2001:
For the Three For the Six
Months Ended Months Ended
June 30, June 30,
2001 2001
--------------------------------------
End of period non-cash mark-to-market
accounting adjustments $39.0 $52.5
Net Gains (losses) realized on early
closeouts and settlements 25.7 17.8
--------------------------------------
Net gain (loss) recorded in
earnings $64.7 $70.3
======================================
Page 17
Other Financial Instruments - Interest rate swaps
The objective of holding interest rate swaps is to manage debt service costs by converting a portion of the
fixed-rate debt into variable-rate debt. An interest rate swap, in general, requires one party to pay a
fixed-rate on the notional amount while the other party pays a floating-rate based on the notional amount.
Management believes that it is prudent to maintain a balance between variable-rate and fixed-rate debt.
The Company assesses interest rate cash flow risk by identifying and measuring changes in interest rate exposure
that impact future cash flows and evaluating hedging opportunities. The Company uses analytical techniques to
measure its exposure to fluctuations in interest rates, including cash flow sensitivity analysis to estimate the
expected impact of changes in interest rates on the Company's future cash flows. The General Partner oversees
the strategies of the Company associated with financial risks and approves instruments that are appropriate for
the Company's requirements.
On January 1, 2001, the Company adopted SFAS 133 which required the Company to record the fair market value of
the interest rate swaps on the balance sheet since the swaps were considered fair value hedges. SFAS 133
required that management determine (at the standard's adoption date) (a) the fair value of the swaps based upon
then current market conditions and (b) the estimated maturity date of the swaps (including an estimate of the
impact of any early termination clauses). The recording of the fair market value of the swaps was offset by an
equal increase in the fair value of the associated hedged debt instruments and, therefore, had no impact on
earnings upon transition. See Note 5 for further information regarding the impact of SFAS 133 on the Company's
fixed-rate long-term debt.
After adoption, the interest rate swaps were dedesignated as hedging instruments due to differences between the
maturity dates of the swaps and the associated hedged debt instruments. Dedesignation means that the financial
instrument (in this case, the interest rate swaps) will not be accounted for using hedge accounting under SFAS
133. Upon dedesignation, any future changes in the fair value of the interest rate swap agreements will be
recorded on the balance sheet through earnings. Dedesignation also entails that the previously associated
hedged item (in this case, the debt instrument) will not be adjusted for future changes in its fair value. As a
result, the $2.3 million change in fair value of the debt instrument recorded at the adoption date of SFAS 133
will be amortized to earnings over the life of the previously associated debt instrument of approximately 10
years.
Despite the dedesignation of the interest rate swaps, these financial instruments continue to be effective in
achieving the risk management objectives for which they were intended. Interest expense for 2001 includes a
$5.5 million benefit related to a change in fair value of the Company's interest rate swaps. The change in fair
value of the interest rate swaps does not represent a cash gain or loss for the Company. The actual cash gain
or loss on the interest rate swap agreements will be based upon market interest rates in effect on the specified
settlement dates in the swap agreements. The $5.5 million benefit is primarily due to the decision of one
counterparty not to exercise its early termination right under its swap agreement with the Company and, to a
lesser extent, lower overall borrowing rates.
Due to the complexity of SFAS 133, the Financial Accounting Standards Board ("FASB") organized a formal
committee, the Derivatives Implementation Group ("DIG"), to provide ongoing recommendations to the FASB about
implementation issues. Implementation guidance issued through the DIG process is still continuing; therefore,
the initial conclusions reached by the Company concerning the application of SFAS 133 upon adoption may be
altered. As a result, additional SFAS 133 transition adjustments may be recorded in future periods as the
Company adopts new DIG interpretations approved by the FASB.
11. SEGMENT INFORMATION
Operating segments are components of a business about which separate financial information is available that is
evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing
performance. Generally, financial information is required to be reported on the basis that it is used internally
for evaluating segment performance and deciding how to allocate resources to segments.
Page 18
The Company has five reportable operating segments: Fractionation, Pipeline, Processing, Octane Enhancement and
Other. The reportable segments are generally organized according to the type of services rendered (or process
employed) and products produced and/or sold, as applicable. The segments are regularly evaluated by the Chief
Executive Officer of the General Partner. Fractionation includes NGL fractionation, butane isomerization
(converting normal butane into high purity isobutane) and polymer grade propylene fractionation services.
Pipeline consists of both liquids and natural gas pipeline systems, storage and import/export terminal
services. Processing includes the natural gas processing business and its related NGL merchant activities.
Octane Enhancement represents the Company's 33.33% ownership interest in a facility that produces motor gasoline
additives to enhance octane (currently producing MTBE). The Other operating segment consists of fee-based
marketing services and other plant support functions.
The Company evaluates segment performance based on gross operating margin. Gross operating margin reported for
each segment represents operating income before depreciation and amortization, lease expense obligations retained
by EPCO, gains and losses on the sale of assets and general and administrative expenses. In addition, segment
gross operating margin is exclusive of interest expense, interest income (from unconsolidated affiliates or
others), dividend income from unconsolidated affiliates, minority interest, extraordinary charges and other
income and expense transactions. The Company's equity earnings from unconsolidated affiliates are included in
segment gross operating margin.
Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are
allocated to each segment on the basis of each asset's or investment's principal operations. The principal
reconciling item between consolidated property, plant and equipment and segment property is
construction-in-progress. Segment property represents those facilities and projects that contribute to gross
operating margin and is net of accumulated depreciation on these assets. Since assets under construction do not
generally contribute to segment gross operating margin, these assets are not included in the operating segment
totals until they are deemed operational.
Segment gross operating margin is inclusive of intersegment revenues, which are generally based on transactions
made at market-related rates. These revenues have been eliminated from the consolidated totals.
Page 19
Information by operating segment, together with reconciliations to the consolidated totals, is presented in the
following table:
Operating Segments Adjs.
------------------------------------------------------------------
Octane and Consol.
Fractionation Pipelines Processing Enhancement Other Elims. Totals
---------------------------------------------------------------------------------------------
Revenues from
external customers
for three months ended:
June 30, 2001 $ 86,566 $178,958 $693,242 $631 $959,397
June 30, 2000 97,004 16,914 478,244 751 592,913
for six months ended:
June 30, 2001 176,245 186,145 1,432,011 1,311 1,795,712
June 30, 2000 188,901 23,926 1,125,101 1,266 1,339,194
Intersegment revenues
for three months ended:
June 30, 2001 44,133 24,631 131,657 96 $(200,517)
June 30, 2000 47,264 14,826 139,654 94 (201,838)
for six months ended:
June 30, 2001 85,785 45,410 241,966 191 (373,352)
June 30, 2000 82,729 28,025 281,885 188 (392,827)
Equity income in
unconsolidated affiliates
for three months ended:
June 30, 2001 1,692 2,125 $5,233 9,050
June 30, 2000 1,725 1,065 8,307 11,097
for six months ended:
June 30, 2001 2,253 3,406 5,402 11,061
June 30, 2000 3,926 3,802 10,812 18,540
Total revenues
for three months ended:
June 30, 2001 132,391 205,714 824,899 5,233 727 (200,517) 968,447
June 30, 2000 145,993 32,805 617,898 8,307 845 (201,838) 604,010
for six months ended:
June 30, 2001 264,283 234,961 1,673,977 5,402 1,502 (373,352) 1,806,773
June 30, 2000 275,556 55,753 1,406,986 10,812 1,454 (392,827) 1,357,734
Gross operating margin
by segment
for three months ended:
June 30, 2001 32,803 24,696 68,112 5,233 411 131,255
June 30, 2000 29,591 14,192 18,486 8,307 872 71,448
for six months ended:
June 30, 2001 58,471 42,819 96,510 5,402 946 204,148
June 30, 2000 63,922 28,827 58,040 10,812 1,426 163,027
Segment property at:
June 30, 2001 357,142 670,311 125,657 7,884 71,798 1,232,792
December 31, 2000 356,207 448,920 126,895 8,942 34,358 975,322
Investments in and advances
to unconsolidated
affiliates at:
June 30, 2001 98,062 221,485 33,000 62,261 414,808
December 31, 2000 105,194 102,083 33,000 58,677 298,954
Page 20
All consolidated revenues were earned in the United States. The operations of the Company are centered along
the Texas, Louisiana and Mississippi Gulf Coast areas.
A reconciliation of segment gross operating margin to consolidated income before minority interest follows:
For Three Months Ended For Six Months Ended
June 30, June 30,
--------------------------------- ---------------------------------
2001 2000 2001 2000
--------------------------------- ---------------------------------
Total segment gross operating margin $131,255 $71,448 $204,148 $163,027
Depreciation and amortization (11,793) (8,754) (21,822) (16,878)
Retained lease expense, net (2,660) (2,687) (5,320) (5,324)
Loss (gain) on sale of assets 6 (2,303) 387 (2,303)
Selling, general and administrative (7,737) (7,658) (13,905) (13,042)
--------------------------------- ---------------------------------
Consolidated operating income 109,071 50,046 163,488 125,480
Interest expense (16,331) (8,070) (23,318) (15,844)
Interest income from unconsolidated affiliates 7 126 31 270
Dividend income from unconsolidated affiliates 2,761 1,632 3,995
Interest income - other 1,479 1,225 5,477 2,706
Other, net (251) (62) (531) (425)
--------------------------------- ---------------------------------
Consolidated income before minority interest $ 93,975 $46,026 $146,779 $116,182
================================= =================================
Page 21
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION.
For the Interim Periods ended June 30, 2001 and 2000
The following discussion and analysis should be read in conjunction with the unaudited consolidated
financial statements and notes thereto of the Company included elsewhere herein.
Cautionary Statement regarding Forward-Looking Information
This quarterly report on Form 10-Q contains various forward-looking statements and information that are
based on the belief of the Company and the General Partner, as well as assumptions made by and information
currently available to the Company and the General Partner. When used in this document, words such as
"anticipate," "estimate," "project," "expect," "plan," "forecast," "intend," "could," "believe," "may" and similar
expressions and statements regarding the plans and objectives of the Company for future operations, are intended
to identify forward-looking statements. Although the Company and the General Partner believe that the
expectations reflected in such forward-looking statements are reasonable, they can give no assurance that such
expectations will prove to be correct. Such statements are subject to certain risks, uncertainties, and
assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove
incorrect, actual results may vary materially from those anticipated, estimated, projected, or expected.
Risk Factors
An investment in the Company's securities involves a degree of risk. Among the key risk factors that
may have a direct bearing on the Company's results of operations and financial condition are: (a) competitive
practices in the industries in which the Company competes, (b) fluctuations in oil, natural gas, and natural gas
liquid ("NGL") prices and production due to weather and other natural and market forces, (c) operational and
systems risks, (d) environmental liabilities that are not covered by indemnity or insurance, (e) the impact of
current and future laws and governmental regulations (including environmental regulations) affecting the NGL
industry in general, and the Company's operations in particular, (f) loss of a significant customer, (g) the use
of financial instruments to hedge commodity and interest rate risks and (h) failure to complete one or more new
projects on time or within budget.
The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, market
uncertainty and a variety of additional factors that are beyond the Company's control. These factors include
the level of domestic oil, natural gas and NGL production, the availability of imported oil and natural gas,
actions taken by foreign oil and natural gas producing nations, the availability of transportation systems with
adequate capacity, the availability of competitive fuels and products, fluctuating and seasonal demand for oil,
natural gas and NGLs and conservation and the extent of governmental regulation of production and the overall
economic environment.
The products that the Company processes, sells or transports are principally used as feedstocks in
petrochemical manufacturing and in the production of motor gasoline and as fuel for residential and commercial
heating. A reduction in demand for the Company's products or processing or transportation services by the
petrochemical, refining or heating industries, whether because of general economic conditions, reduced demand by
consumers for the end products made with NGL products, increased competition from petroleum-based products due to
pricing differences, adverse weather conditions, governmental regulations affecting prices and production levels
of natural gas or the content of motor gasoline or other reasons, could have a negative impact on the Company's
results of operations. A material decrease in natural gas production or crude oil refining, as a result of
depressed commodity prices or otherwise, or a decrease in imports of mixed butanes, could result in a decline in
the volumes of NGLs processed or sold by the Company, thereby reducing revenue and operating income.
In addition, the Company's expectations regarding its future capital expenditures as described in
"Liquidity and Capital Resources" are only its forecasts regarding these matters. These forecasts may be
substantially different from actual results due to various uncertainties including the following key factors:
(a) the accuracy of the Company's estimates regarding its spending requirements, (b) the occurrence of any
unanticipated acquisition opportunities, (c) the need to replace any unanticipated losses in capital assets, (d)
Page 22
changes in the strategic direction of the Company and (e) unanticipated legal, regulatory and contractual
impediments with regards to its construction projects.
For a further description of the tax and other risks of owning limited partner interests in the Company,
see the Company's registration documents (together with any amendments thereto) filed with the SEC on Form S-1/A
dated July 21,1998, Form S-3 dated December 21, 1999 and Form S-3 dated February 23, 2001.
Company Overview
The Company is a publicly traded master limited partnership (NYSE, symbol "EPD") that conducts
substantially all of its business through Enterprise Products Operating L.P. (the "Operating Partnership"), the
Operating Partnership's subsidiaries, and a number of joint ventures with industry partners. The Company was
formed in April 1998 to acquire, own, and operate all of the NGL processing and distribution assets of Enterprise
Products Company ("EPCO"). The general partner of the Company, Enterprise Products GP, LLC, a majority-owned
subsidiary of EPCO, holds a 1.0% general partner interest in the Company and a 1.0101% general partner interest
in the Operating Partnership.
The principal executive office of the Company is located at 2727 North Loop West, Houston, Texas,
77008-1038, and the telephone number of that office is 713-880-6500. References to, or descriptions of, assets
and operations of the Company in this document include the assets and operations of the Operating Partnership and
its subsidiaries.
The Company is a leading North American provider of a wide range of midstream energy services to its
customers along the central and western Gulf Coast. The Company's services include the:
o gathering, transmission and storage of natural gas from both onshore and offshore Louisiana developments;
o purchase and sale of natural gas in south Louisiana;
o processing of natural gas into a merchantable and transportable form of energy that meets industry
quality specifications by removing NGLs and impurities;
o fractionating for a processing fee mixed NGLs produced as by-products of oil and natural gas production
into their component products: ethane, propane, isobutane, normal butane and natural gasoline;
o converting normal butane to isobutane through the process of isomerization;
o producing MTBE from isobutane and methanol;
o transporting NGL products to end users by pipeline and railcar;
o separating high purity propylene from refinery-sourced propane/propylene mix; and
o transporting high purity propylene to plastics manufacturers by pipeline.
Natural gas transported, processed and/or sold by the Company generally is consumed as fuel by residential,
electric and industrial centers. NGL and petrochemical products processed by the Company generally are used as
feedstocks in petrochemical manufacturing, in the production of motor gasoline and as fuel for residential and
commercial heating.
Company Operations and Assets
The Company's operations are concentrated in the Texas, Louisiana, and Mississippi Gulf Coast area. A
large portion of these operations take place in Mont Belvieu, Texas, which is the hub of the domestic NGL
industry and is adjacent to the largest concentration of refineries and petrochemical plants in the United
States. The facilities the Company operates at Mont Belvieu include: (a) one of the largest NGL fractionation
facilities in the United States with a net processing capacity of 131 MBPD; (b) the largest commercial butane
isomerization complex in the United States with a potential isobutane production capacity of 116 MBPD; (c) a MTBE
production facility with a net production capacity of 5 MBPD; and (d) two propylene fractionation units with a
combined production capacity of 31 MBPD. The Company owns all of the assets at its Mont Belvieu facility except
for the NGL fractionation facility, in which it owns an effective 62.5% interest; one of the propylene
fractionation units, in which it owns a 54.6% interest and controls the remaining interest through a long-term
Page 23
lease; the MTBE production facility, in which it owns a 33.3% interest; and one of its three isomerization units
and one deisobutanizer which are held under long-term leases with purchase options.
The Company's operations in Louisiana and Mississippi include varying interests in twelve natural gas
processing plants with a combined capacity of 11.6 Bcf/d and net capacity of 3.2 Bcf/d, six NGL fractionation
facilities with a combined net processing capacity of 159 MBPD and a propylene fractionation facility with a net
capacity of 7 MBPD.
The Company owns, operates or has an interest in approximately 65.0 million barrels of gross NGL and
petrochemical storage capacity (44.3 million barrels of net capacity) in Texas, Louisiana and Mississippi that
are an integral part of its processing operations. The Company also leases and operates one of only two
commercial NGL import/export terminals on the Gulf Coast. In addition, the Company has operating and
non-operating ownership interests in over 2,900 miles of NGL and petrochemical pipelines.
Beginning in January 2001, the Company owns varying equity interests in four Gulf of Mexico offshore
Louisiana natural gas pipeline systems totaling 725 miles of pipeline (with an aggregate gross capacity of 2.85
Bcf/d) and related assets. These equity interests were purchased from EPE at a cost of approximately $112
million. With the completion of the Acadian Gas, LLC ("Acadian Gas") acquisition in April 2001, the Company now
owns varying interests in an additional 1,042 miles of natural gas pipeline systems (with an aggregate gross
capacity of over 1.1 Bcf/d) and related facilities located in south Louisiana. For additional information
regarding these recent investments and business acquisitions, see "Recent acquisitions and other investments"
below.
The Company's operating margins are primarily derived from services provided to its tolling customers
and from merchant activities. In its tolling operations, the Company is paid a fee based on volumes processed,
transported, stored or handled. The Company generally does not take title to products as part of its tolling
operations; however, in those instances where title to products does transfer to the Company, the Company
generally matches the timing and purchase price of the products with those of the sale of the products so as to
reduce or eliminate exposure to fluctuations in commodity prices. Examples of the Company's tolling operations
include isomerization tolling arrangements, propylene fractionation, liquids pipeline transportation services,
fee-based marketing services and most NGL fractionation services. In addition, the Company's newly acquired
natural gas pipeline businesses are viewed as fee-based operations. See "Recent acquisitions and other
investments" below for a further discussion of the impact of commodity price risk on these operations.
In its merchant activities, the Company is exposed to fluctuations in commodity prices. In the
Company's isobutane merchant business (and to a certain extent its propylene fractionation activities), the
Company takes title to feedstock products and sells processed end products. The Company's profitability from
this type of merchant activity is dependent upon the prices of feedstocks and end products, which may vary on a
seasonal basis. In order to limit the exposure to commodity price fluctuations in these business areas, the
company attempts to match the timing and price of its feedstock purchases with those of the sales of end
products. Operating margins from the company's natural gas processing (and related merchant businesses) are
generally derived from the price spread earned on the sale of purity NGL products extracted from natural gas
stream. To the extent the Company takes title to the NGLs removed from the natural gas stream and reimburses the
producer for the reduction in the Btu content and/or the natural gas used as fuel (the "PTR" or "shrinkage"), the
Company's operating margins are affected by the prices of NGLs and natural gas. As part of its natural gas
processing and related merchant activities, the Company uses commodity financial instruments to reduce its
exposure to the market risks associated with changes in natural gas and NGL prices.
Recent acquisitions and other investments
Natural gas pipelines
General. Since January 1, 2001, the Company has invested approximately $338 million (net of cash
acquired) in natural gas pipeline businesses. These include an initial $226 million paid to Shell for the
purchase of Acadian Gas (an onshore Louisiana system) and a combined $112 million paid to EPE for equity
interests in four Gulf of Mexico natural gas pipelines (primarily offshore Louisiana systems). The acquisition
of these natural gas pipeline businesses from EPE and Shell represents a strategic investment for the Company.
Management believes that these assets have attractive growth attributes given the expected long-term increase in
Page 24
natural gas demand for industrial and power generation uses. In addition, these assets extend the Company's
midstream energy service relationship with long-term NGL customers (producers, petrochemical suppliers and
refineries) and provide opportunities for enhanced services to customers as well as generating additional
fee-based cash flows. These businesses are accounted for as part of the Company's Pipeline operating segment.
Natural gas pipeline systems receive natural gas from producers, other pipelines or shippers through
system interconnects and redeliver the natural gas at other points. Generally, natural gas transportation
agreements provide these systems with a fee per unit of volume (generally in MMBtus) transported. Natural gas
pipeline businesses (such as those of Acadian Gas) may also involve gathering and purchasing natural gas from
producers and suppliers and transporting and reselling such natural gas to electric utility companies, local
distribution companies, industrial customers, affiliates of other pipeline and gas marketing companies as well as
transporting and gathering natural gas for shippers on a fee basis. Overall, the Company's Gulf of Mexico
systems do not take title to the natural gas that they transport; the shipper retains title and the associated
commodity price risk. In the Company's Acadian Gas operations, it does take title to certain natural gas
streams and is exposed to commodity price risk through its natural gas inventories and certain of its contracts.
The results of operation for the six months ended June 30, 2001 include three month's impact of the
Acadian Gas acquisition and six month's impact of the Gulf of Mexico natural gas pipelines. See Note 3 of the
Notes to Unaudited Consolidated Financial Statements for selected pro forma financial data regarding these
transactions as if they had both occurred on January 1, 2001 and 2000.
Acadian Gas. On April 2, 2001, the Company acquired Acadian Gas from Shell US Gas and Power LLC, an
affiliate of Shell, for approximately $226 million in cash using proceeds from the issuance of the $450 Million
Senior Notes. The cash purchase price is subject to certain post-closing adjustments expected to be completed
during the third quarter of 2001. The effective date of the transaction was April 1, 2001.
Acadian Gas is involved in the purchase, sale, transportation and storage of natural gas in Louisiana.
Acadian Gas' assets are comprised of the 438-mile Acadian, 577-mile Cypress and 27-mile Evangeline natural gas
pipeline systems, which together have over 1.1 Bcf/d of capacity. These natural gas pipeline systems are
wholly-owned by Acadian Gas with the exception of the Evangeline system in which Acadian Gas holds an approximate
49.5% interest. The assets acquired include a leased natural gas storage facility located in Napoleonville,
Louisiana.
The Acadian, Cypress and Evangeline systems link supplies of natural gas from onshore developments and,
through connections with offshore pipelines, Gulf of Mexico production to local gas distribution companies,
electric generation and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River
corridor. In addition, these systems have interconnects with 12 interstate and four intrastate pipelines and a
bi-directional interconnect with the U.S. natural gas marketplace at Henry Hub.
Interests in four Gulf of Mexico natural gas pipeline systems. On January 29, 2001, the Company
purchased equity interests in four Gulf of Mexico natural gas pipeline systems and related assets from EPE for
$112 million, after taking into account certain post-closing adjustments.
The Company acquired a 50% equity interest in Starfish Pipeline Company LLC ("Starfish") which owns the
Stingray natural gas pipeline system and a related natural gas dehydration facility. The Stingray system is a
375-mile FERC-regulated natural gas pipeline system that transports natural gas and injected condensate from
certain production areas offshore Louisiana in the Gulf of Mexico to onshore transmission systems located in
south Louisiana. The natural gas dehydration facility is connected to the onshore terminal of the Stingray
system in south Louisiana.
In addition to Starfish, the Company acquired a 25.67% equity interest in Ocean Breeze Pipeline Company
LLC ("Ocean Breeze") and Neptune Pipeline Company LLC ("Neptune") as well as a 33.92% equity interest in Nemo
Gathering Company, LLC ("Nemo"). Ocean Breeze and Neptune collectively own the Manta Ray and Nautilus natural
gas gathering and transmission systems located in the Gulf of Mexico offshore Louisiana. The Manta Ray system
comprises approximately 225 miles of unregulated pipelines with a capacity of 750 MMcf/d and related equipment,
the Nautilus system comprises approximately 101 miles of FERC-regulated pipelines with a capacity of 600 MMcf/d,
Page 25
and the Nemo system, when completed in the fourth quarter of 2001, will comprise approximately 24 miles of
pipeline with a capacity of 300 MMcf/d.
Affiliates of Shell own the remaining equity interests in Starfish and varying interests in Ocean
Breeze, Neptune and Nemo. An affiliate of Marathon Oil Company owns an interest in Ocean Breeze and Neptune.
In addition, Shell is the operator of the assets held by Starfish, Ocean Breeze, Neptune and Nemo.
These natural gas pipeline systems and related assets are strategically located to serve continental
shelf and deepwater developments in the central Gulf of Mexico. Management believes that the equity interests
acquired from EPE complement and integrate well with those of the Acadian Gas acquisition. These investments are
expected to benefit the Company's midstream focus by:
o broadening its midstream business by providing additional services to customers; and by
o contributing to the Company's ability to obtain anticipated increases in natural gas production from
deepwater Gulf of Mexico development.
Management believes that these assets have a significant upside potential, since Shell and Marathon have
dedicated production from over 1,000 square miles of Gulf of Mexico offshore Louisiana natural gas leases to
these systems and only a small portion of this total has been developed to date.
Regulatory environment of natural gas systems. The Stingray and Nautilus natural gas pipeline systems
are regulated by the FERC under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Each system
operates under separate FERC approved tariffs that establish rates, terms and conditions under which each system
provides services to its customers. Generally, the FERC's authority extends to:
o transportation of natural gas, rates and charges;
o certification and construction of new facilities;
o extension or abandonment of services and facilities;
o maintenance of accounts and records;
o depreciation and amortization policies;
o acquisition and disposition of facilities;
o initiation and discontinuation of services; and
o various other matters.
As noted above, the Stingray and Nautilus systems have tariffs established through filings with the FERC that
have a variety of terms and conditions, each of which affect the operations of each system and their ability to
recover fees for the services they provide. Generally, changes to these fees or terms can only be implemented
upon approval by the FERC.
Collectively, the Acadian Gas and Gulf of Mexico pipeline systems acquired by the Company are subject to
various governmental and environmental legislation. Each of these systems has a continuing program of
inspection designed to ensure compliance with such legislation including pollution control and pipeline safety
requirements. The Company believes that these systems are in substantial compliance with the applicable
requirements.
Equistar storage facility
In addition to the natural gas pipeline acquisitions, the Company announced on February 1, 2001 that it
had acquired a NGL storage facility from Equistar Chemicals, LP for approximately $3.4 million. The salt dome
storage cavern, which is located near the Company's Mont Belvieu, Texas complex, has a capacity of one million
barrels. The purchase also includes adjacent acreage which would support the development of additional storage
capacity.
Page 26
Current Business Environment
The second quarter of 2001 was a period of recovery for the NGL industry. The decline in natural gas
prices from the record levels of the first quarter of 2001 resulted in increased NGL extraction rates throughout
the industry. Consequently, the Company saw a rebound in NGL volumes available for fractionation and/or
transportation.
At the Company's gas processing facilities, equity NGL production volumes increased from the 46 MBPD
of the first quarter of 2001 to 63 MBPD in the second quarter of 2001. Natural gas prices, which approached
$10 per MMBtu in January 2001, fell to nearly $3 per MMBtu during July 2001. The price of natural gas relative
to the price of NGLs plays a major role in gas processing costs since high natural gas prices result in increased
fuel and shrinkage costs which may, at times, exceed the value of the NGLs extracted from the gas. The low
equity NGL production rate seen in the first quarter was the result of minimal NGL extraction caused by the
abnormally high cost of natural gas. As natural gas prices moderated in the second quarter, NGL extraction rates
at the Company's processing facilities and those of other industry participants increased, resulting in
additional volumes throughout its NGL value chain.
In the second quarter of 2001, NGL prices declined along with those of other forms of energy. The
resultant loss of value has been mitigated (or in some cases, reversed) by the Company's hedging activities.
During the third quarter of 2001, the Company expects that natural gas prices will generally weaken and that NGL
prices will stabilize. In light of these expectations, management continues to monitor its commodity financial
instruments portfolio due to the volatility of the energy markets. Third quarter equity NGL production is
expected to approximate 75 MBPD.
The Company's recently acquired natural gas pipeline businesses (i.e. Acadian Gas and the Gulf of Mexico
joint ventures) have experienced strong demand for their services. In response to the long-term expected
increase in natural gas demand, many producers have stepped up their drilling activities resulting in an increase
in natural gas volumes available for transportation. Producers believe that natural gas demand will increase
near-term due to new gas-fired electric generation facilities commencing operations and a rebound in industrial
and commercial demand with the moderation of natural gas prices and an improving economy. Conversely, any
material downturn in either the domestic or global economy or long-term decrease in natural gas pricing below
$2.75 to $3.00 per MMBTU could result in decreased drilling activities. Barring the latter scenario, the
Company's natural gas pipelines expect to maintain or grow their current throughput levels for the near term
associated with third-party activities, the most significant of which is the start-up of operations at the Shell
Brutus field. This field is expected to generate approximately 130 BBtu/d of natural gas throughput volume and
10 MBPD of equity NGL production by the end of 2001.
During the second quarter of 2001, the Company's isomerization services and isobutane merchant business
benefited from strong demand for isobutane used in the manufacture of gasoline. The increase in demand stemmed
from refiners increasing gasoline production in anticipation of short-term gasoline supply imbalances heading
into the summer driving season. In response, the Company's Mont Belvieu isomerization units ran at near full
rates during the early part of the second quarter with the isobutane merchant business profiting on strong spot
and contract sales. Also, the Company's Houston Ship Channel import facility and related pipeline system
experienced significant volume and margin increases as commercial butane imports (used as feedstock for
isobutane) were transported to Mont Belvieu to satisfy the demands of increased isobutane production. By the
end of the second quarter, isobutane demand returned to more normalized levels as refiners perceived that
gasoline supplies had stabilized. As a result, the Company anticipates that its isomerization and related
merchant business (along with its import dock and related pipelines) will experience normalized margins and
volumes during the third quarter of 2001.
Propylene fractionation margins are slightly less than last year due to continuing weakness in the
propylene markets. Management expects prices to stabilize during the third quarter of 2001 with a slight rise
expected in the fourth quarter of 2001 due to a strengthening domestic economy and increased propylene demand.
The Company's MTBE operations (reported under the Octane Enhancement business segment) experienced healthy
margins early in the second quarter of 2001 due to the seasonal surge in gasoline blending requirements from
refiners; however, as gasoline supplies and demand have stabilized, MTBE prices and margins have fallen. The
Page 27
Company expects results from MTBE operations to be near breakeven for the third and fourth quarters of 2001 as a
result of this seasonal decrease in prices.
With regards to its major liquids pipelines, the Company expects the Louisiana Pipeline System to
benefit from the seasonal rise in propane shipments that are carried on the Dixie Pipeline with the strongest
movements anticipated during the fourth quarter of 2001. EPIK's financial performance is expected to improve
significantly over the last half of 2001. Exports of butane and propane are expected to increase as a result
of moderating domestic prices for both products relative to foreign markets. This situation should make these
products more attractive on the world market and EPIK should benefit from a heavy slate of vessel loadings for
export.
The following table illustrates selected average quarterly prices for natural gas, crude oil, selected
NGL products and polymer grade propylene since the first quarter of 1999:
Polymer
Natural Normal Grade
Gas, Crude Oil, Ethane, Propane, Butane, Isobutane, Propylene,
$/MMBtu $/barrel $/gallon $/gallon $/gallon $/gallon $/pound
-----------------------------------------------------------------------------------------
(a) (b) (a) (a) (a) (a) (a)
Fiscal 1999:
First quarter $1.70 $13.05 $0.20 $0.24 $0.29 $0.31 $0.12
Second quarter $2.12 $17.66 $0.27 $0.31 $0.37 $0.38 $0.13
Third quarter $2.56 $21.74 $0.34 $0.42 $0.49 $0.49 $0.16
Fourth quarter $2.52 $24.54 $0.30 $0.41 $0.52 $0.52 $0.19
Fiscal 2000:
First quarter $2.49 $28.84 $0.38 $0.54 $0.64 $0.64 $0.21
Second quarter $3.41 $28.79 $0.36 $0.52 $0.60 $0.68 $0.26
Third quarter $4.22 $31.61 $0.40 $0.60 $0.68 $0.67 $0.26
Fourth quarter $5.22 $31.98 $0.49 $0.67 $0.75 $0.73 $0.24
Fiscal 2001:
First quarter (c) $7.00 $28.81 $0.43 $0.55 $0.63 $0.69 $0.23
Second quarter (c) $4.61 $27.88 $0.33 $0.46 $0.53 $0.63 $0.19
- ----------------------------------------------------------------------------------------------------------------
(a) Natural gas, NGL and polymer grade propylene prices represent an average of index prices
(b) Crude oil price is representative of West Texas Intermediate
(c) After reaching a high of $9.87 per MMBtu in January 2001, natural gas prices have declined to an
average of $3.68 per MMBtu in June 2001.
Results of Operation of the Company
The Company has five reportable operating segments: Fractionation, Pipeline, Processing, Octane
Enhancement and Other. Fractionation includes NGL fractionation, butane isomerization (converting normal butane
into high purity isobutane) and polymer grade propylene fractionation services. Pipeline consists of liquids and
natural gas pipeline systems, storage and import/export terminal services. Processing includes the natural gas
processing business and its related NGL merchant activities. Octane Enhancement represents the Company's 33.3%
ownership interest in a facility that produces motor gasoline additives to enhance octane (currently producing
MTBE). The Other operating segment consists of fee-based marketing services and other plant support functions.
The management of the Company evaluates segment performance based on gross operating margin ("gross
operating margin" or "margin"). Gross operating margin reported for each segment represents operating income
before depreciation and amortization, lease expense obligations retained by EPCO, gains and losses on the sale of
assets and selling, general and administrative expenses. In addition, segment gross operating margin is
exclusive of interest expense, interest income (from unconsolidated affiliates or others), dividend income from
Page 28
unconsolidated affiliates, minority interest, extraordinary charges and other income and expense transactions.
The Company's equity earnings from unconsolidated affiliates are included in segment gross operating margin.
The Company's gross operating margin by segment (in thousands of dollars) along with a reconciliation to
consolidated operating income for the three and six month periods ended June 30, 2001 and 2000 were as follows:
For Three Months Ended For Six Months Ended
June 30, June 30,
------------------------------------ -----------------------------------
2001 2000 2001 2000
------------------------------------ -----------------------------------
Gross Operating margin by segment:
Fractionation $ 32,803 $29,591 $ 58,471 $ 63,922
Pipeline 24,696 14,192 42,819 28,827
Processing 68,112 18,486 96,510 58,040
Octane enhancement 5,233 8,307 5,402 10,812
Other 411 872 946 1,426
------------------------------------ -----------------------------------
Gross Operating margin total 131,255 71,448 204,148 163,027
Depreciation and amortization 11,793 8,754 21,822 16,878
Retained lease expense, net 2,660 2,687 5,320 5,324
Loss (gain) on sale of assets (6) 2,303 (387) 2,303
Selling, general and administrative expenses 7,737 7,658 13,905 13,042
------------------------------------ -----------------------------------
Consolidated operating income $109,071 $50,046 $163,488 $125,480
==================================== ===================================
The Company's significant production and other volumetric data (on a net basis) for the three and six
month periods ended June 30, 2001 and 2000 were as follows:
For Three Months Ended For Six Months Ended
June 30, June 30,
--------------------------------- ----------------------------------
2001 2000 2001 2000
--------------------------------- ----------------------------------
MBPD, Net
---------
Equity NGL Production 63 72 54 72
NGL Fractionation 202 215 184 217
Isomerization 94 81 82 74
Propylene Fractionation 29 30 30 30
Octane Enhancement 5 5 4 5
Major NGL and Petrochemical Pipelines 519 340 438 350
MMBtu/D, Net
------------
Natural Gas Pipelines 1,295,370 1,263,039
Three Months Ended June 30, 2001 compared with Three Months Ended June 30, 2000
Revenues, Costs and Expenses and Operating Income. The Company's revenues increased 60% to $968.4
million in 2001 compared to $604.0 million in 2000. The Company's operating costs and expenses increased by 56%
to $851.6 million in 2001 versus $546.3 million in 2000. Operating income increased 118% to $109.1 million in
2001 from $50.0 million in 2000. Second quarter 2001 revenues and expenses have primarily been impacted by the
acquisition of Acadian Gas and increased merchant business activities. The majority of the increase in
operating income for 2001 relates to $39.0 million in non-cash mark-to-market gains relating to the Company's
commodity hedging activities.
Fractionation. The Company's gross operating margin for the Fractionation segment increased to $32.8
million in 2001 from $29.6 million in 2000. NGL fractionation margin declined $4.3 million quarter-to-quarter
primarily the result of higher energy costs and lower fractionation volumes. NGL fractionation net volumes were
202 MBPD for 2001 compared to 215 MBPD during 2000. With the decline in natural gas prices since February 2001,
Page 29
NGL fractionation volumes have improved since the first quarter 2001's 165 MBPD rate due to higher liquids
extraction rates at gas processing facilities. The 2000 volume is representative of a period when the industry
was maximizing NGL production.
The Company's isomerization business posted a $6.7 million increase in margin in 2001 over 2000 levels
with isomerization volumes increasing from 81 MBPD in 2000 to 94 MBPD in 2001. The increase in both margin and
volume is attributable to a strong isobutane market early in the second quarter of 2001 which led to an increase
in demand for the Company's isomerization services. Gross operating margin from propylene fractionation
declined by $0.5 million primarily due to moderating prices and a slight decrease in volumes. Propylene
fractionation volumes were 29 MBPD in 2001 versus 30 MBPD during the 2000 period.
Pipeline. The Company's gross operating margin for the Pipeline segment was $24.7 million in 2001
compared to $14.2 million in 2000. Of the $10.5 million increase, $5.2 million is attributable to natural gas
pipelines (i.e., the newly acquired Acadian Gas and the Gulf of Mexico systems) which benefited from a strong
natural gas marketplace. Natural gas pipeline volumes averaged 1,295 BBtu/d on a net basis. Of the Company's
liquids-oriented assets, the recently completed Lou-Tex NGL Pipeline added $2.4 million in margin on volumes of
21 MBPD and the Houston Ship Channel import facility and related pipeline system added $3.1 million primarily due
to strong imports of commercial butane. Net liquids throughput volumes increased to 519 MBPD in 2001 compared
with 340 MBPD in 2000. Of the 179 MBPD increase in net throughput volumes, 143 MBPD is attributable to the
higher import activity.
Processing. For the second quarter of 2001, the Processing segment generated gross operating margin of
$68.1 million compared to $18.5 million during the same period in 2000. The Processing segment includes the
Company's natural gas processing business and related merchant activities. Gross operating margin from natural
gas processing plants posted a $44.1 million increase over 2000 levels primarily due to a $59.1 million increase
in net hedging gains from $5.6 million in 2000 to $64.7 million in 2001 (see discussion below). The net hedging
gains more than offset the effects of lower equity NGL volumes and prices and a rise in energy-related operating
costs. The Company's equity NGL production was 63 MBPD for the 2001 quarter versus 72 MBPD for the same period
in 2000. Although lower on a quarter-to-quarter basis, equity NGL production for the second quarter of 2001
improved from the 46 MBPD rate of the first quarter of 2001. The improvement is related to the overall decline
in natural gas prices that have led processors industrywide to increase NGL recoveries. Gross operating margin
from merchant activities in 2001 increased $5.5 million over 2000 primarily due to strong demand for isobutane.
Gross operating margin for the 2001 period includes $64.7 million of net hedging profits resulting from
the Company's commodity hedging activities. Of this amount, $39.0 million is attributable to net non-cash
mark-to-market gains on the commodity financial instruments that were outstanding at June 30, 2001. The Company
employs various hedging strategies to mitigate the effects of fluctuating commodity prices (primarily NGL prices)
on its natural gas processing business and related merchant activities.
A large number of the Company's commodity financial instruments are based on the historical relationship
between natural gas prices and NGL prices. This type of hedging strategy utilizes the forward sale of natural
gas at a fixed-price with the expected margin on the settlement of the position offsetting or mitigating changes
in the anticipated margins on NGL merchant activities and the value of its NGL equity production. During the
second quarter of 2001, the Company benefited from a decline in natural gas prices relative to its fixed
positions. The decline in natural gas prices created gains on the settlement and early closeout of certain
positions of approximately $25.7 million. If natural gas prices had not declined to the degree seen during the
quarter, a smaller gain or a loss on hedging activities may have resulted offset somewhat by anticipated higher
NGL prices. A variety of factors influence whether or not the Company's hedging strategy is successful. For
additional information regarding the Company's commodity financial instruments, see Item 3 "Quantitative and
Qualitative Disclosures about Market Risk" on page 36.
Octane Enhancement. The Company's gross operating margin for Octane Enhancement decreased $3.1 million
in the second quarter of 2001 compared with 2000 levels. MTBE production, on a net basis, was 5 MBPD in both
2001 and 2000. The decline in margin is primarily due to lower MTBE prices in 2001 relative to the 2000 period
and higher energy costs.
Page 30
Interest expense. Interest expense for the second quarter of 2001 increased $8.3 million over the same
period in 2000. The increase is primarily due to interest associated with the $450 Million Senior Notes issued
in January 2001.
Six Months Ended June 30, 2001 compared with Six Months Ended June 30, 2000
Revenues, Costs and Expenses and Operating Income. The Company's revenues increased 29% to $1.8
billion in 2001 compared to $1.4 billion in 2000. The Company's operating costs and expenses increased by 33%
to $1.6 billion in 2001 versus $1.2 billion in 2000. Operating income increased 30% to $163.5 million in 2001
from $125.5 million in 2000. Year-to-date 2001 revenues and expenses have increased due to the acquisition of
Acadian Gas and increased merchant business activities. In addition year-to-date 2001 expenses have increased
due to higher than normal natural gas prices which affects energy-related operating costs at the Company's
facilities. The majority of the increase in operating income for 2001 relates to $52.5 million in non-cash
mark-to-market gains relating to the Company's commodity hedging activities.
Fractionation. The Company's gross operating margin for the Fractionation segment decreased to $58.5
million from $63.9 million. NGL fractionation margin decreased $14.7 million primarily due to lower processing
volumes and higher energy-related operating costs. NGL fractionation net volumes decreased to 184 MBPD for the
first six months of 2001 compared to 217 MBPD during the same period in 2000. The decrease is the result of
lower extraction rates at gas processing facilities in early 2001 (due to the high cost of natural gas) versus
2000 when the industry was maximizing NGL production. NGL fractionation volumes improved to 202 MBPD during the
second quarter of 2001 as extraction rates increased and the price of natural gas declined. For the first six
months of 2001, gross operating margin from isomerization services increased $11.2 million compared to 2000
primarily due to an increase in volumes and toll processing fees. Isomerization volumes increased to 82 MBPD
during the first six months of 2001 versus 74 MBPD during the same period in 2000 due to increased demand for the
Company's services. Gross operating margin from propylene fractionation decreased $2.8 million compared to the
first six months of 2001 primarily due to higher energy costs and moderating prices. Net propylene fractionation
volumes were 30 MBPD for both periods.
Pipeline. The Company's gross operating margin for the Pipeline segment was $42.8 million compared to
$28.8 million in 2000. Of the $14.0 million increase, $6.9 million is attributable to natural gas
transportation activities (i.e. Acadian Gas and the Gulf of Mexico systems) which benefited from a strong natural
gas marketplace in 2001. The Company's recently completed Lou-Tex NGL Pipeline added $5.1 million on volumes
of 22 MBPD. In addition, margin on the Company's Lou-Tex Propylene Pipeline for 2001 was $2.9 million higher
than 2000 (primarily due to this asset being purchased in March 2000). Strong imports of mixed NGLs
(particularly commercial butanes) resulted in a $3.1 million increase in margins for the Houston Ship Channel
import facility and related pipeline system. The increase in commercial butane imports was related to the
strong demand for isobutane which occurred between February and May 2001.
Overall, net throughput on the Company's major liquids pipelines improved to 438 MBPD in 2001 versus 350
MBPD in 2000, with 76 MBPD of the increase stemming from increased imports and related pipeline activity along
the Houston Ship Channel. Net throughput for the natural gas pipelines averaged 1,263 BBtu/d with Acadian Gas
accounting for 725 BBtu/d and the Gulf of Mexico systems for the balance.
Processing. For the 2001 period, the Processing segment generated gross operating margin of $96.5
million compared to $58.0 million in 2000. Gross operating margin from the natural gas processing plants posted
a $4.1 million increase over 2000 levels primarily due to a $67.3 million increase in net hedging gains from $3.0
million in 2000 to $70.3 million in 2001 (see discussion below). The net hedging gains more than offset the
effects of lower equity NGL volumes and prices and a rise in energy-related operating costs. Equity NGL
production averaged 54 MBPD during the 2001 period compared to 72 MBPD during the 2000 period. The 2001 rate
of 54 MBPD reflects the very low NGL extraction rates of the first quarter of 2001 (46 MBPD) when natural gas
prices were at their peak. As natural gas costs have declined since January 2001, equity NGL production has
begun returning to higher levels (63 MBPD during the second quarter of 2001). The 2000 rate reflects a period in
which processors were operating facilities at near full extraction rates. Gross operating margin from merchant
activities increased $34.4 million over 2000 primarily due to strong demand for propane in the first quarter of
2001 for heating and isobutane in the second quarter of 2001 for refining.
Page 31
Gross operating margin for the 2001 period includes $70.3 million of net hedging profits resulting from
the Company's commodity hedging activities. Of this amount, $52.5 million is attributable to non-cash
mark-to-market gains on the commodity financial instruments that were outstanding at June 30, 2001. As
discussed earlier under the Processing segment's quarter-to-quarter variance explanation (see Page 30), the
Company employs various hedging strategies to mitigate the effects of fluctuating commodity prices (primarily NGL
prices) on its natural gas processing business and related merchant activities. Of the $70.3 million in net
hedging profits, $17.8 million is attributable to realized gains on the settlement and early closeout of certain
positions.
Currently, the predominant strategy employed by the Company utilizes natural gas-based commodity
financial instruments to hedge future NGL production and sales. This type of hedge is based upon the historical
relationship between natural gas and NGL prices. The key factor behind the net hedging gains recognized by the
Company is the decline in natural gas prices relative to the fixed natural gas prices found in its commodity
financial instrument portfolio. If natural gas prices had not declined to the degree seen during the quarter, a
smaller gain or a loss on hedging activities may have resulted which should have been offset somewhat by
correlative higher NGL prices which would have increased the value of the Company's equity NGL production. A
variety of factors influence whether or not the Company's hedging strategy is successful. For additional
information regarding the Company's commodity financial instruments, see Item 3 "Quantitative and Qualitative
Disclosures about Market Risk" on page 36 and the quarter-to-quarter variance explanation for Processing found on
page 31.
Octane Enhancement. The Company's gross operating margin for Octane Enhancement decreased $5.4 million
in the first six months of 2001 compared with the same period in 2000. MTBE production, on a net basis, was 4
MBPD in 2001 and 5 MBPD in 2000. The decline in margin is primarily due to lower MTBE prices in 2001 relative
to the 2000 period, higher energy-related operating costs and a prolonged maintenance outage which lasted from
December 2000 until February 2001.
Interest expense. Interest expense for 2001 increased $7.5 million over 2000. The increase is
attributable to the interest associated with the $450 Million Senior Notes issued in January 2001. Interest
expense for 2001 includes a $5.5 million benefit related to a change in fair value of the Company's interest rate
swaps. The change in fair value of the interest rate swaps does not represent a cash gain or loss for the
Company. The actual cash gain or loss on the interest rate swap agreements will be based upon market interest
rates in effect on the specified settlement dates in the swap agreements. The $5.5 million benefit is primarily
due to the decision of one counterparty not to exercise its early termination right under its swap agreement with
the Company and, to a lesser extent, lower overall borrowing rates.
Liquidity and Capital Resources
General. The Company's primary cash requirements, in addition to normal operating expenses and debt
service, are for capital expenditures (both maintenance and expansion-related), business acquisitions and
distributions to its partners. The Company expects to fund its short-term needs for such items as maintenance
capital expenditures and quarterly distributions to its partners from operating cash flows. Capital expenditures
for long-term needs resulting from future expansion projects and business acquisitions are expected to be funded
by a variety of sources including (either separately or in combination) cash flows from operating activities,
borrowings under bank credit facilities and the issuance of additional Common Units and public debt. The
Company's debt service requirements are expected to be funded by operating cash flows or refinancing arrangements.
As noted above, certain of the Company's liquidity and capital resource requirements are met using
borrowings under bank credit facilities and/or the issuance of additional Common Units or public debt (separately
or in combination). As of June 30, 2001, availability under the Company's revolving bank credit facilities was
$400 million (which may be increased to $500 million under certain conditions). In addition to the existing
revolving bank credit facilities, a subsidiary of the Company issued $450 million of public debt in January 2001
(the "$450 Million Senior Notes") using the remaining shelf availability under its $800 million December 1999
universal shelf registration (the "December 1999 Registration Statement"). The proceeds from this offering were
used to acquire the Acadian Gas and Gulf of Mexico natural gas pipeline systems and to finance the cost to
construct certain NGL pipelines and related projects and for working capital and other general partnership
purposes. On February 23, 2001, the Company filed a $500 million universal shelf registration (the "February
Page 32
2001 Registration Statement") covering the issuance of an unspecified amount of equity or debt securities or a
combination thereof. For a broader discussion of the Company's outstanding debt and changes therein, see the
section below labeled "Long-term Debt".
In June 2000, the Company received approval from its Unitholders to increase by 25,000,000 the number of
Common Units available (and unreserved) to the Company for general partnership purposes during the Subordination
Period. This increase has improved the future financial flexibility of the Company in any potential business
acquisition.
If deemed necessary, management believes that additional financing arrangements can be obtained at
reasonable terms. Management believes that maintenance of the Company's investment grade credit ratings
(currently, Baa2 by Moody's Investor Service and BBB by Standard and Poors) combined with a continued ready
access to debt and equity capital at reasonable rates and sufficient trade credit to operate its businesses
efficiently are a solid foundation to providing the Company with ample resources to meet its long and short-term
liquidity and capital resource requirements.
Operating, Investing and Financing Cash Flows for the six months ended June 30, 2001 and 2000. Cash
flows from operating activities were a $90.6 million inflow for 2001 compared to a $194.8 million inflow in
2000. Cash flows from operating activities primarily reflect the effects of net income, depreciation and
amortization, equity income and distributions from unconsolidated affiliates, fluctuations in fair values of
financial instruments and changes in working capital. Net income increased $30.3 million in 2001 compared to
2000 due to reasons mentioned previously under "Results of Operation of the Company". Depreciation and
amortization increased a combined $4.9 million in 2001 over 2000 primarily due to additional capital expenditures
and business acquisitions. The Company received $13.2 million in distributions from its equity method
investments in 2001 compared to $14.3 million in 2000. The $1.1 million decrease in distributions is primarily
related to a decrease in BEF's earnings due to lower MTBE prices and volumes, lower throughput volumes on the
Tri-States pipeline system and processing volumes at Promix attributable to lower NGL extraction rates during the
early part of 2001 offset by receipts from the newly acquired Gulf of Mexico natural gas pipelines. Operating
cash flow also includes an adjustment for the $55.9 million in non-cash mark-to-market gains related to commodity
and interest rate risk hedging activities. The net effect of changes in operating accounts from period to period
is generally the result of timing of NGL sales and purchases near the end of the period and changes in inventory
values related to pricing or volumes or a combination thereof.
The Company is exposed to various market risks including commodity price risk (primarily through its gas
processing and related NGL businesses) and interest rate risk. The Company attempts to manage its price risk by
utilizing certain hedging strategies defined elsewhere herein. These risks, however, may entail significant
cash outlays in the future that may not be entirely offset by their underlying hedged positions. During 2001,
the Company has recognized $70.3 million in net hedging profits related to its commodity hedging portfolio. Of
this amount, a net $17.8 million has been realized through settlements and the early closeout of certain
positions through June 30, 2001. The remaining $52.5 million represents non-cash mark-to-market gains on
commodity financial instruments that remained open at June 30, 2001. When appropriate, the Company may elect to
close certain of its commodity financial instruments prior to their contractual settlement dates in order to
realize gains or limit losses. As of August 1, 2001, the Company has realized $26.3 million of the $52.5
million in non-cash mark-to-market gains recorded at the end of the second quarter. The realization of the
remaining amount depends upon a number of factors including, most notably, the current market price of natural
gas on the settlement or closing date relative to the price in the underlying financial instruments. If the
price of natural gas rises beyond the hedging positions taken by the Company, it will result in losses rather
than gains on its hedging activities. The Company continues to aggressively monitor its commodity hedging
portfolio in light of the energy markets. For a more complete description of the Company's risk management
policies and potential exposures, see "Item 3. Quantitative and Qualitative Disclosures about Market Risk" on
page 36 and Note 10 of the Notes to Unaudited Consolidated Financial Statements.
Cash used for investing activities was $397.5 million in 2001 compared to $150.7 million in 2000. Cash
outflows included capital expenditures of $57.1 million in 2001 versus $154.2 million in 2000. Capital
expenditures for 2000 include $99.5 million for the purchase of the Lou-Tex Propylene Pipeline and related
assets. In addition, capital expenditures include maintenance capital project costs of $2.7 million in 2001 and
$0.5 million in 2000. The Company's completion of the Acadian Gas business acquisition resulted in an initial
Page 33
payment to Shell of $225.7 million in April 2001, subject to certain post-closing purchase price adjustments.
The 2000 period also includes $6.5 million in cash receipts related to the Company's participation in the BEF
note, which was extinguished in May 2000 with BEF's final principal payment. Lastly, investing cash outflows in
2001 includes $115.3 million in investments in and advances to unconsolidated affiliates compared to $3.0 million
in 2000. The increase is due to the purchase of the Gulf of Mexico natural gas pipeline systems in January
2001.
Cash receipts from financing activities were $362.4 million during 2001 compared to $37.8 million in
2000. Cash flows from financing activities are primarily affected by repayments of debt, borrowings under debt
agreements and distributions to partners. The 2001 period includes proceeds from the $450 Million Senior Notes
issued in January 2001 whereas the 2000 period includes proceeds from the $350 Million Senior Notes and $54
Million MBFC Loan and the associated repayments on various bank credit facilities. Distributions to partners
and the minority interest increased to $76.1 million in 2001 from $67.6 million in 2000 primarily due to an
increase in the quarterly distribution rate.
During the first six months of 2001, the Company has invested $338 million in business acquisitions and
the purchase of interests in other companies. These investments include the acquisition of Acadian Gas and
interests in four natural gas pipelines in the Gulf of Mexico. The Company will continue to analyze potential
acquisitions, joint ventures or similar transactions with businesses that operate in complementary markets and
geographic regions. In recent years, major oil and gas companies have sold non-strategic assets including
assets in the midstream natural gas industry in which the Company operates. Management believes that this trend
will continue, and the Company expects independent oil and natural gas companies to consider similar options.
In addition, management believes that the Company is well positioned to continue to grow through acquisitions
that will expand its platform of assets and through internal growth. The Company anticipates that it will
achieve its annual growth objective for 2001: investing $400 million in energy infrastructure projects and
acquisitions while increasing its cash distribution rate to Unitholders by at least 10% for the full year.
The cash distribution policy (as managed by the General Partner at its sole discretion) allows the
Company to retain a significant amount of cash flow for reinvestment in the growth of the business. Over the
last two years, the Company has reinvested approximately $238 million to fund expansions and acquisitions. The
Company's cash distribution policy provides management with a great deal of financial flexibility in executing
its growth strategy.
Future Capital Expenditures. The Company forecasts that $100.7 million will be spent during the
remainder of 2001 on currently approved capital projects that will be recorded as property, plant and equipment
(the majority of which relate to various pipeline projects such as the Sorrento to Napoleonville pipeline and
Port Arthur to Lake Charles system). In addition, the Company estimates that its share of currently approved
capital expenditures in the projects of its unconsolidated affiliates will be approximately $1.1 million for the
remainder of 2001.
As of June 30, 2001, the Company had $11.3 million in outstanding purchase commitments attributable to
its capital projects. Of this amount, $10.9 million is related to the construction of assets that will be
recorded as property, plant and equipment and $0.4 million is associated with capital projects which will be
recorded as additional investments in unconsolidated affiliates.
New Texas environmental regulations may necessitate extensive redesign and modification of the Company's
Mont Belvieu facilities to achieve the air emissions reductions needed for federal Clean Air Act compliance in
the Houston-Galveston area. Until litigation challenging these regulations is resolved, the technology to be
employed and the cost for modifying the facilities to achieve enough reductions cannot be determined, and capital
funds have not been budgeted for such work. Regardless of the outcome of this litigation, expenditures for
emissions reduction projects will be spread over several years, and management believes the Company will have
adequate liquidity and capital resources to undertake them. For additional information about this litigation,
see the discussion under the topic Clean Air Act--General on page 22 of the Company's Form 10-K for fiscal 2000.
Page 34
Long-term Debt. Long-term debt consisted of the following at:
June 30, December 31,
2001 2000
---------------------------------------
Borrowings under:
$350 Million Senior Notes, 8.25% fixed rate, due March 2005 350,000 350,000
$54 Million MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000
$450 Million Senior Notes, 7.50% fixed rate, due February 2011 450,000
---------------------------------------
Total principal amount 854,000 404,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt 2,015
Less unamortized discount on:
$350 Million Senior Notes (135) (153)
$450 Million Senior Notes (272)
Less current maturities of long-term debt
---------------------------------------
Long-term debt $855,608 $403,847
=======================================
The Company has the ability to borrow under the terms of its $250 Million Multi-Year Credit Facility
and $150 Million 364-Day Credit Facility. No amount was outstanding under either of these two revolving credit
facilities at June 30, 2001 or December 31, 2000.
At June 30, 2001, the Company had a total of $75 million of standby letters of credit capacity under its
$250 Million Multi-Year Credit Facility of which $19.9 million was outstanding.
On January 24, 2001, a subsidiary of the Company completed a public offering of $450 million in
principal amount of 7.50% fixed-rate Senior Notes due February 1, 2011 at a price to the public of 99.937% per
Senior Note (the "$450 Million Senior Notes"). The Company received proceeds, net of underwriting discounts and
commissions, of approximately $446.8 million. The proceeds from this offering were used to acquire the Acadian
Gas and Gulf of Mexico natural gas pipeline systems and to finance the cost to construct certain NGL pipelines
and related projects and for working capital and other general partnership purposes.
The $450 Million Senior Notes were issued under the indenture agreement dated March 15, 2000 which is
also applicable to the $350 Million Senior Notes and therefore are subject to similar covenants and terms. As
with the $350 Million Senior Notes, the $450 Million Senior Notes are:
o subject to a make-whole redemption right;
o an unsecured obligation and rank equally with existing and future unsecured and unsubordinated
indebtedness and senior to any future subordinated indebtedness; and,
o guaranteed by the Company through an unsecured and unsubordinated guarantee.
The Company was in compliance with the restrictive covenants associated with the $350 Million and $450 Million
Senior Notes at June 30, 2001.
The issuance of the $450 Million Senior Notes was a final takedown under the December 1999 Registration
Statement; therefore, the amount of securities available under this universal shelf registration statement was
reduced to zero. On February 23, 2001, the Company filed a $500 million universal shelf registration statement
(the "February 2001 Registration Statement") covering the issuance of an unspecified amount of equity or debt
securities or a combination thereof. The Company expects to use the net proceeds from any sale of securities
under the February 2001 Registration Statement for future business acquisitions and other general corporate
purposes, such as working capital, investments in subsidiaries, the retirement of existing debt and/or the
repurchase of Common Units or other securities. The exact amounts to be used and when the net proceeds will be
applied to partnership purposes will depend on a number of factors, including the Company's funding requirements
and the availability of alternative funding sources. The Company routinely reviews acquisition opportunities.
Page 35
Upon adoption of Statement of Financial Accounting Standards No. 133 ("SFAS 133"), Accounting for
Derivative Instruments and Hedging Activities (as amended and interpreted) on January 1, 2001, the Company
recorded a $2.3 million non-cash increase in the fair value of its fixed-rate debt. SFAS 133 required that the
Company's interest rate swaps and their associated hedged fixed-rate debt be recorded at fair value upon adoption
of the standard. After adoption of the standard, the interest rate swaps were dedesignated due to differences
in the estimated maturity dates of the interest rate swaps versus the fixed-rate debt. As a result, the fair
value of the hedged fixed-rate debt will not be adjusted for future changes in fair value and the $2.3 million
increase in the fair value of the debt will be amortized to earnings over the remaining life of the fixed-rate
debt to which it applies, which approximates 10 years. See Note 5 and Note 10 of the Notes to Unaudited
Consolidated Financial Statements for additional information regarding interest rate swaps and the associated
change in the fair value of the fixed-rate debt.
Recently Issued Accounting Standards
In June 2001, the FASB issued two new pronouncements: SFAS No. 141, " Business Combinations", and SFAS
No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141 prohibits the use of the pooling-of-interest
method for business combinations initiated after June 30, 2001 and also applies to all business combinations
accounted for by the purchase method that are completed after June 30, 2001. There are also transition
provisions that apply to business combinations completed before July 1, 2001, that were accounted for by the
purchase method. SFAS 142 is effective for fiscal years beginning after December 15, 2001 to all goodwill and
other intangible assets recognized in an entity's statement of financial position at that date, regardless of
when those assets were initially recognized. The Company is currently evaluating the provisions of SFAS 141 and
SFAS 142 and has not adopted such provisions in its June 30, 2001 financial statements.
Issuance of last installment of Special Units to Shell
On or about June 30, 2001, Shell met certain year 2001 performance criteria for the issuance of the
remaining 3.0 million non-distribution bearing, convertible Contingency Units (referred to as Special Units once
they are issued). Per a contingent unit agreement with Shell, the Company issued these Special Units on August
2, 2001.
The value of these Special Units was determined to be $117.1 million using persent value techniques.
This amount will increase the purchase price of the TNGL acquisition and the value of the Shell Processing
Agreement when the issue is recorded during the third quarter of 2001. The $117.1 million increase in value of
the Shell Processing Agreement will be amortized over the remaining life of the contract. As a result, the
Company's amortization expense is expected to increase by approximately $1.6 million per quarter ($6.5 million
annually).
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Company is exposed to financial market risks, including changes in commodity prices in its natural
gas and NGL businesses and in interest rates with respect to a portion of its debt obligations. The Company may
use financial instruments (i.e., futures, forwards, swaps, options, and other financial instruments with similar
characteristics) to mitigate these risks. The Company generally does not use financial instruments for
speculative (trading) purposes.
Commodity Price Risk
The Company is exposed to commodity price risk through its natural gas and related NGL businesses. The
prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, market uncertainty
and a variety of additional factors that are beyond the Company's control. These factors include the level of
domestic oil, natural gas and NGL production, the availability of imported oil and natural gas, actions taken by
foreign oil and natural gas producing nations, the availability of transportation systems with adequate capacity,
the availability of alternative fuels and products, seasonal demand for oil, natural gas and NGLs, conservation,
the extent of governmental regulation of production and the overall economic environment.
Page 36
In order to manage this risk, the Company may enter into swaps, forwards, commodity futures, options and
other commodity financial instruments with similar characteristics that are permitted by contract or business
custom to be settled in cash or with another financial instrument. The purpose of these risk management
activities is to hedge exposure to price risks associated with natural gas, NGL production and inventories, firm
commitments and certain anticipated transactions. As an ancillary service, Acadian Gas utilizes commodity
financial instruments to manage the sales price of natural gas for certain of its customers.
The Company has adopted a commercial policy to manage its exposure to the risks generated by its natural
gas and related NGL businesses. The objective of this policy is to assist the Company in achieving its
profitability goals while maintaining a portfolio of conservative risk, defined as remaining within the position
limits established by the General Partner. The Company enters into risk management transactions to manage price
risk, basis risk, physical risk, or other risks related to its commodity positions on both a short-term (less
than 30 days) and long-term basis, not to exceed 18 months. The General Partner oversees the strategies of the
Company associated with physical and financial risks, approves specific activities of the Company subject to the
policy (including authorized products, instruments and markets) and establishes specific guidelines and
procedures for implementing and ensuring compliance with the policy.
The Company assesses the risk of its commodity financial instrument portfolio using a sensitivity
analysis model. The sensitivity analysis performed on this portfolio measures the potential gain or loss in
earnings (i.e., the change in fair value of the portfolio) based on a hypothetical 10% movement in the underlying
quoted market prices of the commodity financial instruments outstanding at the dates noted within the table.
The sensitivity analysis model takes into account the following primary factors and assumptions:
- the current quoted market price of natural gas;
- the current quoted market price of related NGL production;
- changes in the composition of commodities hedged (i.e., the mix
between natural gas and related NGL hedges outstanding);
- fluctuations in the overall volume of commodities hedged (for
both natural gas and related NGL hedges outstanding);
- market interest rates, which are used in determining the present
value; and,
- a liquid market for such financial instruments.
An increase in fair value of the commodity financial instruments (based upon the factors and assumptions
noted above) approximates the gain that would be recognized in earnings if all of the commodity financial
instruments were settled at the respective balance sheet dates. Conversely, a decrease in fair value of the
commodity financial instruments would result in the recording of a loss at the respective balance sheet date.
The sensitivity analysis model does not include the impact that the same hypothetical price movement
would have on the hedged commodity positions to which they relate. Therefore, the impact on the fair value of
the commodity financial instruments of a change in commodity prices would be offset by a corresponding gain or
loss on the hedged commodity positions, assuming:
- the commodity financial instruments are not closed out in advance
of their expected term,
- the commodity financial instruments function effectively as
hedges of the underlying risk, and
- as applicable, anticipated underlying transactions settle as
expected.
The Company routinely reviews its open commodity financial instruments in light of current market
conditions. If market conditions warrant, some instruments may be closed out in advance of their contractual
settlement dates thus realizing a gain or loss depending on the specific exposure. When this occurs, the
Company may enter into new commodity financial instruments to reestablish the hedge of the commodity position to
which the closed instrument relates.
Under the guidelines of SFAS 133, as amended and interpreted, a hedge is normally regarded as effective
if, among other things, at inception and throughout the life of the hedge, the Company could expect changes in
the fair value of the hedged item to be almost fully offset by the changes in the fair value of the hedging
instrument. Currently, the Company's commodity financial instruments do not qualify as effective hedges under
Page 37
the guidelines of SFAS 133, with the result being that changes in the fair value of these financial instruments
are recorded on the balance sheet and in earnings through mark-to-market accounting. The use of mark-to-market
accounting for the commodity financial instruments portfolio results in a degree of non-cash earnings volatility
that is dependant upon changes in the underlying commodity prices. Even though the commodity financial
instruments do not qualify for hedge accounting treatment under the specific guidelines of SFAS 133, the Company
views these financial instruments as hedges in as much as this was the intent when such contracts are executed.
This characterization is consistent with the actual economic performance of the contracts and the Company expects
these financial instruments to continue to mitigate commodity price risk in the future. For additional
information regarding commodity financial instruments, see Note 10 of the Notes to Unaudited Consolidated
Financial Statements.
Sensitivity Analysis for Commodity Financial Instruments Portfolio
Estimates of Fair Value ("FV") and Earnings Impact ("EI")
due to selected changes in quoted market prices at dates selected
December June August
31, 2000 30, 2001 7, 2001
------------------------------------------
(in millions of dollars)
------------------------------------------
FV assuming no change in quoted market prices, Asset (Liability) $(38.6) $ 49.2 $32.7
FV assuming 10% increase in quoted market prices, Asset (Liability) $(56.3) $ 37.4 $24.9
EI assuming 10% increase in quoted market prices, Gain (Loss) $(17.7) $(11.8) $(7.8)
FV assuming 10% decrease in quoted market prices, Asset (Liability) $(20.9) $ 61.5 $41.2
EI assuming 10% decrease in quoted market prices, Gain (Loss) $ 17.7 $ 12.3 $ 8.5
The fair value of the commodity financial instruments at December 31, 2000 was estimated at $38.6
million payable. On June 30, 2001, the fair value of the commodity financial instruments outstanding was
estimated at $49.2 million receivable. The change in fair value between December 31, 2000 and June 30, 2001 was
primarily due to the lower natural gas prices, settlement of certain open positions and a change in the
composition of commodities hedged. By August 7, 2001, the fair value of the commodity financial instruments was
$32.7 million reflecting the early closeout of certain positions and changes in natural gas prices since June 30,
2001.
Historical gains or losses resulting from these hedging activities are a component of the Company's
operating costs and expenses as reflected in its Statements of Consolidated Operations.
Interest rate risk
Variable-rate Debt. At June 30, 2001 and 2000, the Company had no variable rate debt outstanding and as
such had no financial instruments in place to cover any potential interest rate risk on its variable-rate debt
obligations. Variable-rate debt obligations do expose the Company to possible increases in interest expense and
decreases in earnings if interest rates were to rise.
Fixed-rate Debt. In March 2000, the Company entered into interest rate swaps whereby the fixed-rate of
interest on a portion of the $350 Million Senior Notes and the $54 Million MBFC Loan was effectively swapped for
floating-rates tied to the six month London Interbank Offering Rate ("LIBOR"). The objective of holding
interest rate swaps is to manage debt service costs by effectively converting a portion of the fixed-rate debt
into variable-rate debt. An interest rate swap, in general, requires one party to pay a fixed-rate on the
notional amount while the other party pays a floating-rate based on the notional amount. Management believes
that it is prudent to maintain a balance between variable-rate and fixed-rate debt.
The Company assesses interest rate cash flow risk by identifying and measuring changes in interest rate
exposure that impact future cash flows and by evaluating hedging opportunities. The Company uses analytical
techniques to measure its exposure to fluctuations in interest rates, including cash flow sensitivity analysis to
Page 38
estimate the expected impact of changes in interest rates on the Company's future cash flows. The General
Partner oversees the strategies of the Company associated with financial risks and approves instruments that are
appropriate for the Company's requirements.
The following table presents the hypothetical changes in fair values arising from immediate selected
potential changes in quoted market prices of the Company's interest rate swaps outstanding at the dates noted
within the table. The sensitivity analysis model used to estimate the fair values of the interest rate swaps
takes into account the following primary factors/assumptions: (a)current market interest rates (including
forward LIBOR rates and current federal funds rate), (b) early termination options exercisable by the
counterparty (if the fair value of the swap indicates a receivable) and (c) a liquid market for interest rate
swaps. An increase in fair value of the interest rate swaps approximates the gain that would be recognized in
earnings if all of the interest rate swaps were settled at the respective balance sheet dates. Conversely, a
decrease in fair value of the interest rate swaps would result in the recording of a loss at the respective
balance sheet date. The gains or losses resulting from the interest rate hedging activities are a component of
the Company's interest expense as reflected in its Statements of Consolidated Operations.
Sensitivity Analysis for Interest Rate Swap Portfolio
Estimates of Fair Value ("FV") and Earnings Impact ("EI")
due to selected changes in quoted market prices at dates selected
December June August
31, 2000 30, 2001 7, 2001
------------------------------------------
(Estimates in millions of dollars)
------------------------------------------
FV assuming no change in quoted market prices, Asset (Liability) $ 2.5 $ 7.1 $ 8.8
FV assuming 10% increase in quoted market prices, Asset (Liability) $ 1.9 $ 5.9 $ 7.6
EI assuming 10% increase in quoted market prices, Gain (Loss) $(0.6) $(1.2) $(1.2)
FV assuming 10% decrease in quoted market prices, Asset (Liability) $ 3.1 $ 8.4 $ 9.9
EI assuming 10% decrease in quoted market prices, Gain (Loss) $ 0.6 $ 1.3 $ 1.1
The interest rate swaps outstanding at December 31, 2000 reflected a notional amount of $154 million of
fixed-rate debt with the fair value of swaps estimated at $2.5 million. By June 30, 2001, the notional amount
had been reduced to $104 million due to the early termination of one of the swaps by a counterparty with the
aggregate fair value of the remaining swaps estimated at $7.1 million. The change in fair value between
December 31, 2000 and June 30, 2001 is primarily related to lower interest rates and the decision by one
counterparty not to exercise its early termination right. At August 7, 2001, the fair value of the interest rate
swaps was estimated at $8.8 million due to lower interest rates.
The Company's interest rate swap agreements were dedesignated as hedging instruments after the adoption
of SFAS 133; therefore, the interest rate swap agreements are accounted for on a mark-to-market basis. However,
these financial instruments continue to be effective in achieving the risk management activities for which they
were intended. As a result, the change in fair value of these instruments will be reflected on the balance sheet
and in earnings (interest expense) using mark-to-market accounting. For additional information regarding the
interest rate swaps, see Note 10 of the Notes to Unaudited Consolidated Financial Statements that are part of
this Form 10-Q quarterly report.
Other. At June 30, 2001 and December 31, 2000, the Company had $123.3 million and $60.4 million
invested in cash and cash equivalents, respectively. All cash equivalent investments other than cash are highly
liquid, have original maturities of less than three months, and are considered to have insignificant interest
rate risk.
Page 39
Counterparty risk
The Company has credit risk from its extension of credit for sales of products and services, and has
credit risk with its counterparties in terms of settlement risk and performance risk associated with its
commodity financial instruments and interest rate swap agreements. On all transactions where the Company is
exposed to credit risk, the Company analyzes the counterparty's financial condition prior to entering into an
agreement, establishes credit limits and monitors the appropriateness of these limits on an ongoing basis. The
counterparty to a majority of the Company's commodity financial instruments is a major Houston, Texas-based
energy company. The credit risk to this party is somewhat mitigated by cash or letters of credit held by the
Company in an amount dependent upon the exposure to the counterparty.
Related Accounting Developments
Due to the complexity of SFAS 133, the FASB organized a formal committee, the Derivatives Implementation
Group ("DIG"), to provide ongoing recommendations to the FASB about implementation issues. Implementation
guidance issued through the DIG process is still continuing; therefore, the initial conclusions reached by the
Company concerning the application of SFAS 133 upon adoption may be altered. As a result, additional SFAS 133
transition adjustments may be recorded in future periods as the Company adopts new DIG interpretations approved
by the FASB. For additional information regarding SFAS 133, see Note 10 of the Notes to Unaudited Consolidated
Financial Statements.
PART II. OTHER INFORMATION
Item 2. Use of Proceeds
The following table shows the Use of Proceeds from the $450 Million Senior Notes offering completed on
January 29, 2001. The $450 Million Senior Notes represented a takedown of the remaining shelf availability
under the Company's December 1999 Registration Statement filed with the Securities and Exchange Commission (File
Nos. 333-93239 and 333-93239-01, effective January 14, 2000).
The title of the registered debt securities was "7.50% Senior Notes Due 2011." The underwriters of the
offering were Goldman, Sachs and Co., Salomon Smith Barney Inc., Banc One Capital Markets, Inc., First Union
Securities, Inc., Scotia Capital (USA) Inc. and Tokyo-Mitsubishi International plc. The 10-year Senior Notes
have a maturity date of February 1, 2011 and bear a fixed-rate interest coupon of 7.50%.
Amounts
(in millions)
--------------
Proceeds:
Sale of $450 Million Senior Notes to public at 99.937% per Note $ 450
Less underwriting discount of 0.650% per Note (3)
--------------
Total proceeds $ 447
==============
Use of Proceeds:
Initial payment to finance Acadian Gas acquisition $(226)
To finance investment in various Gulf of Mexico
natural gas pipelines (112)
To finance remainder of the costs to construct certain NGL
pipelines and related projects, and for working capital
and other general Company purposes (109)
--------------
Total uses of funds $(447)
==============
The initial $226 million payment to Shell for Acadian Gas was made in April 2001, subject to certain post-closing
purchase price adjustments. Also, the Company paid EPE $112 million in January 2001 for the purchase of equity
interests in four Gulf of Mexico natural gas pipeline systems (Starfish, Ocean Breeze, Neptune and Nemo).
Page 40
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
*2.1 Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated as of
September 22, 2000. (Exhibit 10.1 to Form 8-K filed on September 26, 2000).
*3.1 Form of Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P.
(Exhibit 3.2 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998).
*3.2 Second Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P. dated
September 17, 1999. (The Company incorporates by reference the above document included as Exhibit "D"
to the Schedule 13D filed September 27, 1999 by Tejas Energy, LLC.
*3.3 First Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC dated
September 17, 1999. (Exhibit 99.8 on Form 8-K/A-1 filed October 27, 1999).
*3.4 Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Enterprise Products
Partners L.P. dated June 9, 2000. (Exhibit 3.6 to Form 10-Q filed August 11, 2000).
*4.1 Form of Common Unit certificate. (Exhibit 4.1 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 21, 1998).
*4.2 Unitholder Rights Agreement among Tejas Energy LLC, Tejas Midstream Enterprises, LLC, Enterprise
Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products Company, Enterprise
Products GP, LLC and EPC Partners II, Inc. dated September 17, 1999. (The Company incorporates by
reference the above document included as Exhibit "C" to the Schedule 13D filed September 27, 1999 by
Tejas Energy, LLC.
*4.3 Contribution Agreement by and among Tejas Energy LLC, Tejas Midstream Enterprises, LLC, Enterprise
Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products Company, Enterprise
Products GP, LLC and EPC Partners II, Inc. dated September 17, 1999. (The Company incorporates by
reference the above document included as Exhibit "B" to the Schedule 13D filed September 27, 1999 by
Tejas Energy, LLC.
*4.4 Registration Rights Agreement between Tejas Energy LLC and Enterprise Products Partners L.P. dated
September 17, 1999. (The Company incorporates by reference the above document included as Exhibit "E"
to the Schedule 13D filed September 27, 1999 by Tejas Energy, LLC.
*4.5 Form of Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer,
Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee. (Exhibit
4.1 on Form 8-K filed March 10, 2000).
*4.6 Form of Global Note representing $350 million principal amount of 8.25% Senior Notes Due 2005.
(Exhibit 4.2 on Form 8-K filed March 10, 2000).
*4.7 $250 Million Multi-Year Revolving Credit Agreement among Enterprise Products Operating L.P., First Union
National Bank, as administrative agent; Bank One, NA, as documentation agent; and The Chase Manhattan
Bank, as syndication agent and the Several Banks from time to time parties thereto dated November 17,
2000. (Exhibit 4.2 on Form 8-K filed January 25, 2001).
*4.8 $150 Million 364-Day Revolving Credit Agreement among Enterprise Products Operating L.P. and First Union
National Bank, as administrative agent; Bank One, NA, as documentation agent; and The Chase Manhattan
Page 41
Bank, as syndication agent and the Several Banks from time to time parties thereto dated November 17,
2000. (Exhibit 4.3 on Form 8-K filed January 25, 2001).
*4.9 Guaranty Agreement (relating to the $250 Million Multi-Year Revolving Credit Agreement) by Enterprise
Products Partners L.P. in favor of First Union National Bank, as administrative agent dated November 17,
2000. (Exhibit 4.4 on Form 8-K filed January 25, 2001).
*4.10 Guaranty Agreement (relating to the $150 Million 364-Day Revolving Credit Agreement) by Enterprise
Products Partners L.P. in favor of First Union National Bank, as administrative agent dated November 17,
2000. (Exhibit 4.5 on Form 8-K filed January 25, 2001).
*4.11 Form of Global Note representing $450 million principal amount of 7.50% Senior Notes due 2011. (Exhibit
4.1 to Form 8-K filed January 25, 2001).
*4.12 First Amendment to $250 million Multi-Year Revolving Credit Agreement dated April 19, 2001.
*10.1 Articles of Merger of Enterprise Products Company, HSC Pipeline Partnership, L.P., Chunchula Pipeline
Company, LLC, Propylene Pipeline Partnership, L.P., Cajun Pipeline Company, LLC and Enterprise
Products Texas Operating L.P. dated June 1, 1998.(Exhibit 10.1 to Registration Statement on Form S-1/A,
File No: 333-52537, filed on July 8, 1998).
*10.2 Form of EPCO Agreement among Enterprise Products Partners L.P., Enterprise Products Operating
L.P., Enterprise Products GP, LLC and Enterprise Products Company. (Exhibit 10.2 to Registration
Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998).
*10.3 Transportation Contract between Enterprise Products Operating L.P. and Enterprise Transportation Company
dated June 1, 1998. (Exhibit 10.3 to Registration Statement on Form S-1/A, File No. 333-52537, filed on
July 8, 1998).
*10.4 Venture Participation Agreement among Sun Company, Inc. (R and M), Liquid Energy Corporation and Enterprise
Products Company dated May 1, 1992. (Exhibit 10.4 to Registration Statement on Form S-1,
File No. 333-52537, filed on May 13, 1998).
*10.5 Partnership Agreement among Sun BEF, Inc., Liquid Energy Fuels Corporation and Enterprise Products
Company dated May 1, 1992. (Exhibit 10.5 to Registration Statement on Form S-1, File No. 333-52537,
filed on May 13, 1998).
*10.6 Amended and Restated MTBE Off-Take Agreement between Belvieu Environmental Fuels and Sun Company, Inc.
(R and M) dated August 16, 1995. (Exhibit 10.6 to Registration Statement on Form S-1, File No. 333-52537,
filed on May 13, 1998).
*10.7 Propylene Facility and Pipeline Agreement between Enterprise Petrochemical Company and Hercules
Incorporated dated December 13, 1978. (Exhibit 10.9 to Registration Statement on Form S-1, File No.
333-52537, dated May 13, 1998).
*10.8 Restated Operating Agreement for the Mont Belvieu Fractionation Facilities Chambers County, Texas among
Enterprise Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company and Champlin Petroleum
Company dated July 17, 1985. (Exhibit 10.10 to Registration Statement on Form S-1/A, File No. 333-52537,
filed on July 8, 1998).
*10.9 Ratification and Joinder Agreement relating to Mont Belvieu Associates Facilities among Enterprise
Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company, Champlin Petroleum Company and
Mont Belvieu Associates dated July 17, 1985. (Exhibit 10.11 to Registration Statement on Form S-1/A,
File No. 333-52537, filed on July 8, 1998).
Page 42
*10.10 Amendment to Propylene Facility and Pipeline Sales Agreement between HIMONT U.S.A., Inc. and Enterprise
Products Company dated January 1, 1993. (Exhibit 10.12 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 8, 1998).
*10.11 Amendment to Propylene Facility and Pipeline Agreement between HIMONT U.S.A., Inc. and Enterprise
Products Company dated January 1, 1995. (Exhibit 10.13 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 8, 1998).
*10.12 Fourth Amendment to Conveyance of Gas Processing Rights among Tejas Natural Gas Liquids, LLC and Shell
Oil Company, Shell Exploration and Production Company, Shell Offshore Inc., Shell Deepwater Development
Inc., Shell Land and Energy Company and Shell Frontier Oil and Gas Inc. dated August 1, 1999. (Exhibit
10.14 to Form 10-Q filed on November 15, 1999).
10.13 Fifth Amendment to Conveyance of Gas Processing Rights dated as of April 1, 2001 among Enterprise Gas
Processing, LLC, Shell Oil Company, Shell Exploration and Production Company, Shell Offshore, Inc., Shell
Consolidated Energy Resources, Inc., Shell Land and Energy Company and Shell Frontier Oil and Gas, Inc.
* Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith
(b) Reports on Form 8-K
The following Form 8-K reports were filed during the quarter ending June 30, 2001:
8-K filed on April 4, 2001. On April 2, 2001, the Company announced that its Operating Partnership had
completed the purchase of Acadian Gas from an affiliate of Shell. The effective date of the transaction was
April 1, 2001.
Page 43
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned thereunto duly authorized.
Enterprise Products Partners L.P.
(A Delaware Limited Partnership)
By: Enterprise Products GP, LLC
as General Partner
/s/ Michael J. Knesek
------------------------------
Vice President, Controller and
Date: August 13, 2001 Principal Accounting Officer
